Oxidative coupling of methane implementations for olefin production

ABSTRACT

The present disclosure provides oxidative coupling of methane (OCM) systems for small scale and world scale production of olefins. An OCM system may comprise an OCM subsystem that generates a product stream comprising C 2+  compounds and non-C 2+  impurities from methane and an oxidizing agent. At least one separations subsystem downstream of, and fluidically coupled to, the OCM subsystem can be used to separate the non-C 2+  impurities from the C 2+  compounds. A methanation subsystem downstream and fluidically coupled to the OCM subsystem can be used to react H 2  with CO and/or CO 2  in the non-C 2+  impurities to generate methane, which can be recycled to the OCM subsystem. The OCM system can be integrated in a non-OCM system, such as a natural gas liquids system or an existing ethylene cracker.

CROSS-REFERENCE

This application is a continuation application of U.S. patentapplication Ser. No. 14/592,668, filed Jan. 8, 2015, which applicationclaims the benefit of U.S. Provisional Patent Application Ser. No.61/925,627, filed Jan. 9, 2014, U.S. Provisional Patent Application Ser.No. 61/955,112, filed Mar. 18, 2014, U.S. Provisional Patent ApplicationSer. No. 61/996,789, filed May 14, 2014, U.S. Provisional PatentApplication Ser. No. 62/050,720, filed Sep. 15, 2014, U.S. ProvisionalPatent Application Ser. No. 62/073,478, filed Oct. 31, 2014, and U.S.Provisional Patent Application Ser. No. 62/086,650, filed Dec. 2, 2014,each of which is entirely incorporated herein by reference.

BACKGROUND

The modern petrochemical industry makes extensive use of cracking andfractionation technology to produce and separate various desirablecompounds from crude oil. Cracking and fractionation operations areenergy intensive and generate considerable quantities of greenhousegases.

The gradual depletion of worldwide petroleum reserves and thecommensurate increase in petroleum prices may place extraordinarypressure on refiners to minimize losses and improve efficiency whenproducing products from existing feedstocks, and also to seek viablealternative feedstocks capable of providing affordable hydrocarbonintermediates and liquid fuels to downstream consumers.

Methane may provide an attractive alternative feedstock for theproduction of hydrocarbon intermediates and liquid fuels due to itswidespread availability and relatively low cost when compared to crudeoil. Worldwide methane reserves may be in the hundreds of years atcurrent consumption rates and new production stimulation technologiesmay make formerly unattractive methane deposits commercially viable.

Ethylene is an important commodity chemical intermediate. The worldwideproduction of ethylene exceeds that of any organic compound. Ethylene isused in the production of polyethylene plastics, polyvinyl chloride,ethylene oxide, ethylene chloride, ethylbenzene, alpha-olefins, linearalcohols, vinyl acetate, and fuel blendstocks such as, but not limitedto, aromatics, alkanes and alkenes. The growth in demand for ethyleneand ethylene based derivatives is forecast to increase as the developingworld continues to register higher economic growth. The bulk ofworldwide annual commercial production of ethylene is based on thermalcracking of petroleum hydrocarbons with stream; the process is commonlycalled pyrolysis or steam cracking The feedstocks for steam cracking canbe derived either from crude oil (e.g., naphtha) or from associated ornatural gas (e.g., ethane, propane, LPG). Ethylene production isprimarily limited to high volume production as a commodity chemical inrelatively large steam crackers or other petrochemical complexes thatalso process the large number of other hydrocarbon byproducts generatedin the steam cracking process. Producing ethylene from far more abundantand significantly less expensive methane in natural gas provides anattractive alternative to ethylene produced from steam cracking (e.g.,naphtha or gaseous feedstocks). Oligomerization processes can be used tofurther convert ethylene into longer chain hydrocarbons useful aspolymer components for plastics, vinyls, and other high value polymericproducts. Additionally, these oligomerization processes may be used toconvert ethylene to other longer hydrocarbons, such as C₆, C₇, C₈ andlonger hydrocarbons useful for fuels like gasoline, diesel, jet fuel andblendstocks for these fuels, as well as other high value specialtychemicals.

SUMMARY

Recognized herein is the need for efficient and commercially viablesystems and methods for converting methane to higher chain hydrocarbons,such as hydrocarbon compounds with two or more carbon atoms (also “C₂₊compounds” herein), such as olefins and/or alkanes. An oxidativecoupling of methane (“OCM”) reaction is a process by which methane canform one or more C₂₊ compounds.

In an OCM process, methane is oxidized to yield products comprising C₂₊compounds, including alkanes (e.g., ethane, propane, butane, pentane,etc.) and alkenes (e.g., ethylene, propylene, etc.). Such alkane (also“paraffin” herein) products may not be suitable for use in downstreamprocesses. Unsaturated chemical compounds, such as alkenes (or olefins),may be employed for use in downstream processes. Such compounds may bepolymerized to yield polymeric materials, which may be employed for usein various commercial settings.

An aspect of the present disclosure provides oxidative coupling ofmethane (OCM) system for small scale or world scale production ofolefins, comprising: (a) an OCM subsystem that (i) takes as input a feedstream comprising methane (CH₄) and a feed stream comprising anoxidizing agent, and (ii) generates from the methane and the oxidizingagent a product stream comprising C₂₊ compounds and non-C₂₊ impurities;and (b) at least one separations subsystem downstream of, andfluidically coupled to, the OCM subsystem, wherein the separationssubsystem comprises a first heat exchanger, a de-methanizer unitdownstream of the first heat exchanger, and a second heat exchangerdownstream of the de-methanizer unit, wherein (1) the first heatexchanger cools the product stream, (2) the de-methanizer unit acceptsthe product stream from the first heat exchanger and generates anoverhead stream comprising methane and at least a portion of the non-C₂₊impurities, and a bottoms stream comprising at least a portion of theC₂₊ compounds, and (3) at least a portion of the overhead stream iscooled in the second heat exchanger and is subsequently directed to thefirst heat exchanger to cool the product stream.

In some embodiments of aspects provided herein, the overhead stream issplit into at least two streams, and at least one of the two streams ispressurized prior to introduction to the second heat exchanger. In someembodiments of aspects provided herein, the system further comprises ahydrogenation unit downstream of the de-methanizer, wherein thehydrogenation unit accepts a stream comprising the C₂₊ compounds andhydrogenates alkynes in the C₂₊ compounds to alkanes and/or alkenes. Insome embodiments of aspects provided herein, the system furthercomprises a de-ethanizer unit downstream of the hydrogenation unit,wherein the de-ethanizer unit accepts the stream and separates ethanefrom ethylene. In some embodiments of aspects provided herein, thesystem further comprises a methanation subsystem upstream of the OCMsubsystem, wherein the methanation subsystem reacts H₂ with CO and/orCO₂ to generate methane, which methane is directed to the OCM subsystem.In some embodiments of aspects provided herein, the system furthercomprises a sulfur removal subsystem upstream of the OCM subsystem,wherein the sulfur removal subsystem accepts a feed stream comprisingmethane and decrease the concentration of sulfur in the feed stream. Insome embodiments of aspects provided herein, the sulfur removalsubsystem further comprises a heat recovery steam generator unit. Insome embodiments of aspects provided herein, the system furthercomprises an absorption system downstream of the OCM subsystem, whereinthe absorption system decreases the concentration of CO₂ in the productstream. In some embodiments of aspects provided herein, the absorptionsystem comprises an absorption unit and a scrubber downstream of theabsorption unit. In some embodiments of aspects provided herein, theoxidizing agent is O₂. In some embodiments of aspects provided herein,the O₂ is provided by air. In some embodiments of aspects providedherein, the OCM subsystem comprises at least one OCM reactor. In someembodiments of aspects provided herein, the OCM subsystem comprises atleast one post-bed cracking unit downstream of the at least one OCMreactor, which post-bed cracking unit is configured to convert at leasta portion of alkanes in the product stream to alkenes. In someembodiments of aspects provided herein, the system further comprises anon-OCM process upstream of the OCM subsystem. In some embodiments ofaspects provided herein, the non-OCM process is a natural gas liquidsprocess. In some embodiments of aspects provided herein, the non-C₂₊impurities comprise one or more of nitrogen (N₂), oxygen (O₂), water(H₂O), argon (Ar), carbon monoxide (CO), carbon dioxide (CO₂) and CH₄.

An aspect of the present disclosure provides an oxidative coupling ofmethane (OCM) system for small scale or world scale production ofolefins, comprising: (a) an OCM subsystem that (i) takes as input a feedstream comprising methane (CH₄) and a feed stream comprising anoxidizing agent, and (ii) generates from the methane and the oxidizingagent a product stream comprising C₂₊ compounds and non-C₂₊ impurities;and (b) at least one methanation subsystem downstream of, andfluidically coupled to, the OCM subsystem, wherein the methanationsubsystem reacts H₂ and CO and/or CO₂ included in the non-C₂₊ impuritiesto generate methane.

In some embodiments of aspects provided herein, at least a portion ofthe methane generated in the methanation subsystem is recycled to theOCM subsystem. In some embodiments of aspects provided herein, theoxidizing agent is O₂. In some embodiments of aspects provided herein,the O₂ is provided by air. In some embodiments of aspects providedherein, the OCM subsystem comprises at least one OCM reactor. In someembodiments of aspects provided herein, the OCM subsystem comprises atleast one post-bed cracking unit downstream of the at least one OCMreactor, which post-bed cracking unit is configured to convert at leasta portion of alkanes in the product stream to alkenes. In someembodiments of aspects provided herein, the system further comprises anon-OCM process upstream of the OCM subsystem. In some embodiments ofaspects provided herein, the non-OCM process is a natural gas liquidsprocess. In some embodiments of aspects provided herein, the non-C₂₊impurities comprise one or more of nitrogen (N₂), oxygen (O₂), water(H₂O), argon (Ar), carbon monoxide (CO), carbon dioxide (CO₂) and CH₄.In some embodiments of aspects provided herein, the methanationsubsystem comprises at least one methanation reactor.

An aspect of the present disclosure provides a catalyst forhydrogenation of acetylene in an oxidative coupling of methane (OCM)process comprising at least one metal element, wherein the catalyst iscapable of decreasing the concentration of acetylene to less than about100 parts per million (ppm) in an OCM effluent.

In some embodiments of aspects provided herein, the catalyst is capableof decreasing the concentration of acetylene to less than about 10 ppmin the OCM effluent. In some embodiments of aspects provided herein, thecatalyst is capable of decreasing the concentration of acetylene to lessthan about 1 ppm in the OCM effluent. In some embodiments of aspectsprovided herein, the at least one metal element is palladium. In someembodiments of aspects provided herein, the at least one metal elementis part of a metal oxide. In some embodiments of aspects providedherein, the catalyst is capable of providing an OCM effluent thatcomprises at least about 0.5% carbon monoxide. In some embodiments ofaspects provided herein, the catalyst is capable of providing an OCMeffluent that comprises at least about 1% carbon monoxide. In someembodiments of aspects provided herein, the catalyst is capable ofproviding an OCM effluent that comprises at least about 3% carbonmonoxide. In some embodiments of aspects provided herein, the catalysthas a lifetime of at least about 1 year. In some embodiments of aspectsprovided herein, the catalyst is capable of providing an OCM effluentthat comprises at least about 0.1% acetylene. In some embodiments ofaspects provided herein, the catalyst is capable of providing an OCMeffluent that comprises at least about 0.3% acetylene. In someembodiments of aspects provided herein, the catalyst is capable ofproviding an OCM effluent that comprises at least about 0.5% acetylene.In some embodiments of aspects provided herein, the at least one metalelement comprises a plurality of metal elements.

An aspect of the present disclosure provides a catalyst for convertingcarbon monoxide (CO) and/or carbon dioxide (CO₂) into methane (CH₄) inan oxidative coupling of methane (OCM) process, wherein the catalystcomprises at least one metal element for converting CO and/or CO₂ intoCH₄ at a selectivity for the formation of methane that is at least about10-fold greater than the selectivity of the catalyst for formation ofcoke in an OCM effluent.

In some embodiments of aspects provided herein, the catalyst has aselectivity for the formation of methane that is at least about 100-foldgreater than the selectivity of the catalyst for formation of coke. Insome embodiments of aspects provided herein, the catalyst has aselectivity for the formation of methane that is at least about1000-fold greater than the selectivity of the catalyst for formation ofcoke. In some embodiments of aspects provided herein, the catalyst has aselectivity for the formation of methane that is at least about10000-fold greater than the selectivity of the catalyst for formation ofcoke. In some embodiments of aspects provided herein, the OCM effluentcomprises at least about 3% olefin and/or acetylene compounds. In someembodiments of aspects provided herein, the OCM effluent comprises atleast about 5% olefin and/or acetylene compounds. In some embodiments ofaspects provided herein, the OCM effluent comprises at least about 10%olefin and/or acetylene compounds. In some embodiments of aspectsprovided herein, the at least one metal element is nickel. In someembodiments of aspects provided herein, the at least one metal elementis part of a metal oxide.

An aspect of the present disclosure provides a method for preventingcoke formation on a methanation catalyst in an oxidative coupling ofmethane (OCM) process, the method comprising (a) providing an OCMeffluent comprising carbon monoxide (CO) and/or carbon dioxide (CO₂) and(b) using a methanation catalyst to perform a methanation reaction withthe OCM effluent, wherein (i) hydrogen and/or water is added to the OCMeffluent prior to (b), (ii) olefins and/or acetylene in the OCM effluentis hydrogenated prior to (b); and/or (iii) olefins and/or acetylene areseparated and/or condensed from the OCM effluent prior to (b).

In some embodiments of aspects provided herein, (iii) is performed usingabsorption or adsorption. In some embodiments of aspects providedherein, the methanation reaction forms at least about 1000-fold moremethane than coke. In some embodiments of aspects provided herein, themethanation reaction forms at least about 10000-fold more methane thancoke. In some embodiments of aspects provided herein, the methanationreaction forms at least about 100000-fold more methane than coke. Insome embodiments of aspects provided herein, the method furthercomprises any two of (i), (ii) and (iii). In some embodiments of aspectsprovided herein, the method further comprises all of (i), (ii) and(iii).

An aspect of the present disclosure provides an oxidative coupling ofmethane (OCM) system for production of olefins and power, comprising:(a) an OCM subsystem that (i) takes as input a feed stream comprisingmethane (CH₄) and a feed stream comprising an oxidizing agent, and (ii)generates from the methane and the oxidizing agent a product streamcomprising C₂₊ compounds and heat; and (b) a power subsystem fluidicallyand/or thermally coupled to the OCM subsystem that converts the heatinto electrical power.

In some embodiments of aspects provided herein, the oxidizing agent isO₂. In some embodiments of aspects provided herein, the O₂ is providedby air. In some embodiments of aspects provided herein, the OCMsubsystem comprises at least one OCM reactor. In some embodiments ofaspects provided herein, the OCM subsystem comprises at least onepost-bed cracking unit within the at least one OCM reactor or downstreamof the at least one OCM reactor, which post-bed cracking unit isconfigured to convert at least a portion of alkanes in the productstream to alkenes. In some embodiments of aspects provided herein, thepower subsystem is a gas turbine combined cycle (GTCC). In someembodiments of aspects provided herein, the system further comprises asteam generator for generating steam from the heat, which steam isconverted to electrical power in the power subsystem. In someembodiments of aspects provided herein, the power subsystem comprises agas turbine and un-reacted methane from the OCM subsystem is convertedto electrical power using the gas turbine. In some embodiments ofaspects provided herein, a ratio of production of C²⁻ alkenes andproduction of power can be varied by adjusting a composition of the feedstream. In some embodiments of aspects provided herein, a ratio ofproduction of C₂₊ alkenes and production of power can be varied byadjusting an amount of C₂₊ alkanes fed into a post-bed cracking sectionof the OCM subsystem.

An aspect of the present disclosure provides a method for producing atleast one C₂₊ alkene and power, comprising: (a) directing methane and anoxidizing agent into a reactor comprising a catalyst unit, wherein thecatalyst unit comprises an oxidative coupling of methane (OCM) catalystthat facilitates an OCM reaction that produces C₂₊ alkene; (b) reactingthe methane and oxidizing agent with the aid of the OCM catalyst togenerate at least one OCM product comprising at least one C₂₊ compoundand heat; and (c) generating electrical power from the heat.

In some embodiments of aspects provided herein, the heat is converted tosteam and the steam is converted to power in a steam turbine. In someembodiments of aspects provided herein, un-reacted methane from thereactor is converted to electrical power in a gas turbine. In someembodiments of aspects provided herein, the reactor comprises a crackingunit downstream of the catalyst unit, wherein the cracking unitgenerates C₂₊ alkene from C₂₊ alkane, and wherein the method furthercomprises; (d) providing at least one hydrocarbon-containing stream thatis directed through the cracking unit, which hydrocarbon-containingstream comprises at least one C₂₊ alkane; and (e) in the cracking unit,cracking the at least one C₂₊ alkane to provide the at least one C₂₊alkene in a product stream that is directed out of the reactor. In someembodiments of aspects provided herein, the hydrocarbon-containingstream comprises at least one OCM product. In some embodiments ofaspects provided herein, the C₂₊ alkene produced from the at least onehydrocarbon-containing stream in the cracking unit is in addition to theC₂₊ alkene produced from the methane and the oxidizing agent in thereactor. In some embodiments of aspects provided herein, the amount ofsteam produced is varied or the amount of at least onehydrocarbon-containing stream that is directed through the cracking unitis varied to alter the amount of electrical power produced and theamount of C₂₊ alkene produced. In some embodiments of aspects providedherein, the OCM catalyst is a nanowire catalyst. In some embodiments ofaspects provided herein, the oxidizing agent is O₂. In some embodimentsof aspects provided herein, the at least one C₂₊ alkane comprises aplurality of C₂₊ alkanes. In some embodiments of aspects providedherein, the cracking unit generates C₂₊ alkene from C₂₊ alkane with theaid of the heat generated in the OCM reaction. In some embodiments ofaspects provided herein, the reactor is adiabatic.

An aspect of the present disclosure provides a method for producinghydrocarbon compounds including two or more carbon atoms (C₂₊compounds), the method comprising: (a) performing an oxidative couplingof methane (OCM) reaction in an OCM reactor to produce an OCM effluentcomprising carbon dioxide (CO₂), hydrogen (H₂), one or more C₂₊compounds, and methane (CH₄); (b) separating the OCM effluent into (i) afirst stream comprising at least some of the one or more C₂₊ compoundsand (ii) a second stream comprising carbon monoxide (CO), CO₂, H₂, andCH₄; (c) methanating the second stream to produce a first OCM reactorfeed comprising CH₄ formed from the H₂ and CO and/or CO₂ in the secondstream; (d) methanating a third stream comprising CH₄ and H₂ to producea second OCM reactor feed comprising CH₄, which third stream is from anethylene cracker; and (e) directing the first and second OCM reactorfeeds to the OCM reactor.

In some embodiments of aspects provided herein, the second stream andthe third stream are methanated in a single methanation reactor. In someembodiments of aspects provided herein, the method further comprisesproviding at least a portion of the first stream to the ethylenecracker. In some embodiments of aspects provided herein, the at leastthe portion of the first stream is provided to a gas compressor or afractionation unit of the ethylene cracker. In some embodiments ofaspects provided herein, the third stream is the overhead stream of ademethanizer unit of the ethylene cracker. In some embodiments ofaspects provided herein, the separating in (b) is performed at least inpart in a pressure swing adsorption (PSA) unit. In some embodiments ofaspects provided herein, the separating in (b) is performed at least inpart with a CO₂ removal system or a process gas dryer. In someembodiments of aspects provided herein, the OCM effluent is compressedprior to (b). In some embodiments of aspects provided herein, the methodfurther comprises feeding oxygen (O₂) as an oxidizing agent to the OCMreactor, which O₂ takes part in the OCM reaction. In some embodiments ofaspects provided herein, the OCM effluent comprises carbon monoxide (CO)that is converted into CH₄ in (c). In some embodiments of aspectsprovided herein, the OCM reaction further reacts CH₄ from natural gas toachieve additional ethylene production. In some embodiments of aspectsprovided herein, the third stream further comprises CH₄.

An aspect of the present disclosure provides an oxidative coupling ofmethane (OCM) system for production of hydrocarbon compounds includingtwo or more carbon atoms (C²⁻ compounds), comprising: (a) an OCMsubsystem that (i) takes as input a first feed stream comprising methane(CH₄) and a second feed stream comprising an oxidizing agent, and (ii)generates a product stream comprising C₂₊ compounds from the CH₄ and theoxidizing agent; (b) a separation subsystem fluidically coupled to theOCM subsystem that separates the product stream into (i) a first streamcomprising C²⁻ compounds and (ii) a second stream comprising hydrogen(H₂) and carbon dioxide (CO₂) and/or carbon monoxide (CO); (c) amethanation subsystem fluidically coupled to the second stream and tothe OCM subsystem, wherein the methanation subsystem converts H₂ and CO₂and/or CO into CH₄; and (d) an ethylene cracker subsystem fluidicallycoupled to the methanation subsystem that provides CH₄ H₂ , CO₂ and/orCO to the methanation subsystem.

In some embodiments of aspects provided herein, the methanationsubsystem provides CH₄ to the OCM subsystem. In some embodiments ofaspects provided herein, at least some of the additional H₂ is derivedfrom a demethanizer of the ethylene cracker subsystem. In someembodiments of aspects provided herein, the first stream is fluidicallycoupled to the ethylene cracker subsystem. In some embodiments ofaspects provided herein, the first stream is fractionated in theethylene cracker subsystem. In some embodiments of aspects providedherein, the separation subsystem comprises a pressure swing adsorption(PSA) unit. In some embodiments of aspects provided herein, the OCMsubsystem reacts CH₄ from natural gas with the oxidizing agent in an OCMreaction. In some embodiments of aspects provided herein, the oxidizingagent comprises O₂. In some embodiments of aspects provided herein, theO₂ is generated from air. In some embodiments of aspects providedherein, the OCM subsystem comprises at least one OCM reactor. In someembodiments of aspects provided herein, the OCM subsystem comprises atleast one post-bed cracking unit within the at least one OCM reactor ordownstream of the at least one OCM reactor, which post-bed cracking unitis configured to convert at least a portion of alkanes in the productstream to alkenes. In some embodiments of aspects provided herein, thereactor is adiabatic.

An aspect of the present disclosure provides a method for producinghydrocarbon compounds including two or more carbon atoms (C₂₊compounds), the method comprising: (a) performing an oxidative couplingof methane (OCM) reaction in an OCM reactor to produce an OCM effluentstream comprising carbon dioxide (CO₂), hydrogen (H₂), one or more C₂₊compounds, and methane (CH₄); (b) separating the OCM effluent streaminto a first stream comprising at least some of the one or more C₂₊compounds and a second stream comprising carbon monoxide (CO), CO₂, H₂,and CH₄; (c) methanating the second stream to produce a first methanatedstream comprising CH₄ formed from the H₂ and CO and/or CO₂ in the secondstream; (d) removing at least a portion of the first methanated stream;and (e) directing the portion of the first methanated stream into anatural gas pipeline.

In some embodiments of aspects provided herein, (e) comprises directingthe portion of the first methanated stream into the natural gas pipelinein exchange for an item of value.

An aspect of the present disclosure provides a method for producinghydrocarbon compounds including two or more carbon atoms (C₂₊compounds), the method comprising: (a) performing a natural gas liquids(NGL) extraction in an NGL extraction unit to produce an NGL streamcomprising ethane, propane, and/or butane and a methane streamcomprising methane; (b) directing the methane stream to an oxidativecoupling of methane (OCM) reactor; and (c) performing an OCM reaction inthe OCM reactor using the methane stream to produce an OCM effluentcomprising carbon dioxide (CO₂), hydrogen (H₂), one or more C₂₊compounds, and methane (CH₄).

An aspect of the present disclosure provides a method for producinghydrocarbon compounds including two or more carbon atoms (C₂₊compounds), the method comprising: (a) performing an oxidative couplingof methane (OCM) reaction in an OCM reactor to produce an OCM effluentstream comprising carbon dioxide (CO₂), hydrogen (H₂), one or more C₂₊compounds, and methane (CH₄); (b) separating the OCM effluent streaminto a first stream comprising at least some of the one or more C₂₊compounds and a second stream comprising carbon monoxide (CO), CO₂, H₂,and CH₄; (c) directing the second stream to a Fischer-Tropsch (F-T)reactor; (d) in the F-T reactor, performing an F-T reaction using thesecond stream to produce a first OCM reactor feed comprising CH₄ formedfrom the H₂ and CO in the second stream; and (e) directing the first OCMreactor feeds to the OCM reactor.

An aspect of the present disclosure provides a method for producinghydrocarbon compounds including two or more carbon atoms (C₂₊compounds), the method comprising: (a) performing an oxidative couplingof methane (OCM) reaction in an OCM reactor to produce an OCM effluentstream comprising carbon dioxide (CO₂), hydrogen (H₂), one or more C₂₊compounds, and methane (CH₄); (b) separating the OCM effluent streaminto a first stream comprising at least some of the one or more C₂₊compounds and a second stream comprising carbon monoxide (CO), CO₂, H₂,and CH₄; and (c) directing the OCM effluent stream to a heat recoverysteam generator (HRSG) system; (d) with the HRSG system, transferringheat from the OCM effluent stream to a water stream to produce steam.

An aspect of the present disclosure provides a method for producinghydrocarbon compounds including two or more carbon atoms (C₂₊compounds), the method comprising: (a) performing an oxidative couplingof methane (OCM) reaction in an OCM reactor to produce an OCM effluentstream comprising carbon dioxide (CO₂), hydrogen (H₂), one or more C₂₊compounds, and methane (CH₄); (b) separating the OCM effluent streaminto a first stream comprising at least some of the one or more C₂₊compounds and a second stream comprising carbon monoxide (CO), CO₂, H₂,and CH₄; (c) directing the second stream and an air stream to a gascompressor, and burning at least a portion of the second stream andcompressing the air stream to produce a compressed air stream; (d)separating the compressed air stream in an air separation unit (ASU)into an third stream comprising O₂ and a fourth stream comprising N₂;and (e) feeding the oxygen-rich stream to the OCM reactor.

An aspect of the present disclosure provides a method for producinghydrocarbon compounds including two or more carbon atoms (C₂₊compounds), the method comprising: (a) performing an oxidative couplingof methane (OCM) reaction in an OCM reactor to produce an OCM effluentstream comprising carbon dioxide (CO₂), hydrogen (H₂), one or more C₂₊compounds, and methane (CH₄); (b) transferring heat from the OCMeffluent stream in a first heat exchanger and a second heat exchangerdownstream of the first heat exchanger with respect to a flow directionof the OCM effluent stream, thereby cooling the OCM effluent stream; (c)demethanizing the OCM effluent stream in a demethanizer, therebyproducing an overhead stream comprising carbon dioxide (CO₂), hydrogen(H₂), and methane (CH₄) and a bottom stream comprising one or more C²⁻compounds; (d) expanding the overhead stream, thereby cooling theoverhead stream; (e) transferring heat to the overhead stream in thesecond heat exchanger and the first heat exchanger downstream of thesecond heat exchanger with respect to a flow direction of the overheadstream, thereby heating the overhead stream; and (f) feeding theoverhead stream from the first heat exchanger into the OCM reactor.

An aspect of the present disclosure provides a method for producinghydrocarbon compounds including two or more carbon atoms (C₂₊compounds), the method comprising: (a) performing an oxidative couplingof methane (OCM) reaction in an OCM reactor to produce an OCM effluentstream comprising carbon dioxide (CO₂), hydrogen (H₂), one or more C₂₊compounds, and methane (CH₄); (b) transferring heat from the OCMeffluent stream in a first heat exchanger and subsequently expanding theOCM effluent stream, thereby cooling the OCM effluent stream; (c)demethanizing the OCM effluent stream in a demethanizer, therebyproducing an overhead stream comprising carbon dioxide (CO₂), hydrogen(H₂), and methane (CH₄) and a bottom stream comprising one or more C²⁻compounds; (d) transferring heat to a first portion of the overheadstream in a second heat exchanger and the first heat exchangerdownstream of the second heat exchanger with respect to a flow directionof the first portion of the overhead stream, thereby heating the firstportion of the overhead stream; (e) compressing a second portion of theoverhead stream and, in a phase separation unit, separating the secondportion of the overhead stream into a liquid stream and a vapor stream;and (f) directing the liquid stream through the second heat exchangerand into the demethanizer.

In some embodiments of aspects provided herein, the method furthercomprises expanding the vapor stream to cool the vapor stream. In someembodiments of aspects provided herein, the method further comprisestransferring heat to the vapor stream in the second heat exchanger andthe first heat exchanger.

An aspect of the present disclosure provides a method for producinghydrocarbon compounds including two or more carbon atoms (C₂₊compounds), the method comprising: (a) performing an oxidative couplingof methane (OCM) reaction in an OCM reactor to produce an OCM effluentstream comprising carbon dioxide (CO₂), hydrogen (H₂), one or more C₂₊compounds, and methane (CH₄); (b) transferring heat from the OCMeffluent stream in a first heat exchanger and subsequently expanding theOCM effluent stream, thereby cooling the OCM effluent stream; (c)demethanizing the OCM effluent stream in a demethanizer, therebyproducing an overhead stream comprising carbon dioxide (CO₂), hydrogen(H₂), and methane (CH₄) and a bottom stream comprising one or more C₂₊compounds; (d) compressing a first portion of the overhead stream,thereby heating the first portion of the overhead stream, andsubsequently in a second heat exchanger transferring heat from the firstportion of the overhead stream, thereby cooling the first portion of theoverhead stream; (e) in a phase separation unit, separating the firstportion of the overhead stream into a liquid stream and a vapor stream;and (f) transferring heat from the liquid stream in a third heatexchanger and subsequently directing the liquid stream into thedemethanizer.

In some embodiments of aspects provided herein, the method furthercomprises: expanding the vapor stream, thereby cooling the vapor stream;and transferring heat to the vapor stream in the third heat exchanger,the second heat exchanger, and/or the first heat exchanger, therebyheating the vapor stream. In some embodiments of aspects providedherein, the method further comprises: expanding a second portion of theoverhead stream, thereby cooling the second portion of the overheadstream; and transferring heat to the second portion of the overheadstream in the third heat exchanger, the second heat exchanger, and/orthe first heat exchanger, thereby heating the second portion of theoverhead stream.

An aspect of the present disclosure provides a method for producinghydrocarbon compounds including two or more carbon atoms (C₂₊compounds), the method comprising: (a) performing an oxidative couplingof methane (OCM) reaction in an OCM reactor to produce an OCM effluentstream comprising carbon dioxide (CO₂), hydrogen (H₂), one or more C₂₊compounds, and methane (CH₄); (b) transferring heat from the OCMeffluent stream in a first heat exchanger, thereby cooling the OCMeffluent stream; (c) demethanizing the OCM effluent stream in ademethanizer, thereby producing an overhead stream comprising carbondioxide (CO₂), hydrogen (H₂), and methane (CH₄) and a bottom streamcomprising one or more C₂₊ compounds; (d) compressing a first portion ofthe overhead stream, thereby heating the first portion of the overheadstream, and subsequently transferring heat from the first portion of theoverhead stream in a second heat exchanger, thereby cooling the firstportion of the overhead stream; (e) in a first phase separation unit,separating the first portion of the overhead stream into a first liquidstream and a first vapor stream; (f) expanding the vapor stream, therebycooling the first vapor stream and subsequently transferring heat to thefirst vapor stream in the second heat exchanger and/or the first heatexchanger, thereby heating the first vapor stream; and (g) sub-coolingand flashing the first liquid stream to produce a two-phase stream and,in a second phase separation unit, separating the two-phase stream intoa second liquid stream and a second vapor stream, and directing thesecond liquid stream to the demethanizer.

An aspect of the present disclosure provides a method for producinghydrocarbon compounds with two or more carbon atoms (C₂₊ compounds), themethod comprising: (a) performing an oxidative coupling of methane (OCM)reaction in an OCM system comprising two or more OCM reactor stages toproduce an OCM effluent stream comprising carbon dioxide (CO₂), hydrogen(H₂), one or more C₂₊ compounds, and methane (CH₄); (b) separating theOCM effluent into a first stream comprising at least some of the one ormore C₂₊ compounds and a second stream comprising carbon monoxide (CO),CO₂, H₂, and CH₄; (c) methanating the second stream to produce a firstOCM reactor feed comprising CH₄ formed from the H₂ and CO and/or CO₂ inthe second stream; and (d) directing the first OCM reactor feed to theOCM reactor.

An aspect of the present disclosure provides a method for producinghydrocarbon compounds including two or more carbon atoms (C₂₊compounds), the method comprising: (a) performing an oxidative couplingof methane (OCM) reaction in an OCM reactor using air as an oxidant toproduce an OCM effluent stream comprising carbon dioxide (CO₂), hydrogen(H₂), one or more C²⁻ compounds, and methane (CH₄); (b) separating theOCM effluent stream into a first stream comprising at least some of theone or more C₂₊ compounds and a second stream comprising carbon monoxide(CO), CO₂, H₂, and CH₄; (c) methanating the second stream to produce anOCM reactor feed comprising CH₄ formed from the H₂ and CO and/or CO₂ inthe second stream; and (d) directing the OCM reactor feed to the OCMreactor.

An aspect of the present disclosure provides a method for producinghydrocarbon compounds including two or more carbon atoms (C₂₊compounds), the method comprising: (a) performing an oxidative couplingof methane (OCM) reaction in an OCM reactor using O₂ as an oxidant toproduce an OCM effluent stream comprising carbon dioxide (CO₂), hydrogen(H₂), one or more C²⁻ compounds, and methane (CH₄); (b) separating theOCM effluent stream into a first stream comprising at least some of theone or more C₂₊ compounds and a second stream comprising carbon monoxide(CO), CO₂, H₂, and CH₄; (c) methanating the second stream to produce anOCM reactor feed comprising CH₄ formed from the H₂ and CO and/or CO₂ inthe second stream; and (d) directing the OCM reactor feed to the OCMreactor.

In some embodiments of aspects provided herein, the OCM reactor feedcomprises water.

An aspect of the present disclosure provides a method for producinghydrocarbon compounds including two or more carbon atoms (C₂₊compounds), the method comprising: (a) performing an oxidative couplingof methane (OCM) reaction in an OCM reactor to produce an OCM effluentstream comprising carbon dioxide (CO₂), hydrogen (H₂), one or more C₂₊compounds, and methane (CH₄); (b) separating the OCM effluent streaminto a first stream comprising at least some of the one or more C₂₊compounds and a second stream comprising carbon monoxide (CO), CO₂, H₂,and CH₄; (c) separating the second stream in a pressure swing adsorption(PSA) unit to produce an OCM reactor feed comprising CH₄ and a thirdstream comprising H₂ and CO and/or CO₂; and (d) directing the OCMreactor feed to the OCM reactor.

An aspect of the present disclosure provides a method for producinghydrocarbon compounds including two or more carbon atoms (C₂₊compounds), the method comprising: (a) performing an oxidative couplingof methane (OCM) reaction in an OCM reactor to produce an OCM effluentstream comprising carbon dioxide (CO₂), hydrogen (H₂), one or more C₂₊compounds, and methane (CH₄); (b) separating the OCM effluent streaminto a first stream comprising at least some of the one or more C₂₊compounds and a second stream comprising carbon monoxide (CO), CO₂, H₂,and CH₄; (c) separating the second stream in a membrane separation unitto produce an OCM reactor feed comprising CH₄ and a third streamcomprising H₂ and CO and/or CO₂; and (d) directing the OCM reactor feedto the OCM reactor.

An aspect of the present disclosure provides a method for producinghydrocarbon compounds including two or more carbon atoms (C₂₊compounds), the method comprising: (a) performing an oxidative couplingof methane (OCM) reaction in an OCM reactor to produce an OCM effluentstream comprising carbon dioxide (CO₂), hydrogen (H₂), one or more C₂₊compounds, and methane (CH₄); (b) separating the OCM effluent stream ina pressure swing adsorption (PSA) unit into a first stream comprising atleast some of the one or more C₂₊ compounds and CH₄ and a second streamcomprising carbon monoxide (CO), CO₂, and H₂; (c) separating the firststream in a demethanizer unit to produce an OCM reactor feed comprisingCH₄ and a third stream comprising the at least some of the one or moreC₂₊ compounds; and (d) directing the OCM reactor feed to the OCMreactor.

An aspect of the present disclosure provides a method for producinghydrocarbon compounds including two or more carbon atoms (C₂₊compounds), the method comprising: (a) performing an oxidative couplingof methane (OCM) reaction in an OCM reactor to produce an OCM effluentstream comprising carbon dioxide (CO₂), hydrogen (H₂), one or more C₂₊compounds, and methane (CH₄); (b) separating the OCM effluent stream ina pressure swing adsorption (PSA) unit into a first stream comprisingCH₄ and a second stream comprising at least some of the one or more C₂₊compounds, carbon monoxide (CO), CO₂, and H₂; (c) separating the secondstream to produce a third stream comprising the at least some of the oneor more C₂₊ compounds and a fourth stream comprising carbon monoxide(CO), CO₂, and H₂; and (d) directing the first stream to the OCMreactor.

Additional aspects and advantages of the present disclosure will becomereadily apparent to those skilled in this art from the followingdetailed description, wherein only illustrative embodiments of thepresent disclosure are shown and described. As will be realized, thepresent disclosure is capable of other and different embodiments, andits several details are capable of modifications in various obviousrespects, all without departing from the disclosure. Accordingly, thedrawings and description are to be regarded as illustrative in nature,and not as restrictive.

INCORPORATION BY REFERENCE

All publications, patents, and patent applications mentioned in thisspecification are herein incorporated by reference to the same extent asif each individual publication, patent, or patent application wasspecifically and individually indicated to be incorporated by reference.

BRIEF DESCRIPTION OF THE DRAWINGS

The novel features of the invention are set forth with particularity inthe appended claims. A better understanding of the features andadvantages of the present invention will be obtained by reference to thefollowing detailed description that sets forth illustrative embodiments,in which the principles of the invention are utilized, and theaccompanying drawings or figures (also “FIG.” and “FIGS.” herein), ofwhich:

FIG. 1 is a block flow diagram of a system that is configured togenerate olefins, such as ethylene;

FIGS. 2A and 2B show an oxidative coupling of methane (OCM) system forsmall scale olefin production;

FIG. 3 is a process flow diagram of a system that comprises ahydrogenation unit and a deethanizer unit, which can be employed forsmall scale and world scale olefin production;

FIG. 4 is process flow diagram of a sulfur removal system for smallscale olefin production;

FIG. 5 shows a process flow diagram of a sulfur removal system for worldscale olefin production;

FIGS. 6A and 6B show methanation systems that can be used with systemsof the present disclosure;

FIG. 7 shows an example of a methanation system for OCM;

FIGS. 8A and 8B show an OCM system for world scale olefin production;

FIG. 9 shows a separation system that may be employed for use withsystems and methods of the present disclosure;

FIG. 10 shows another separation system that may be employed for usewith systems and methods of the present disclosure;

FIG. 11 shows another separation system that may be employed for usewith systems and methods of the present disclosure;

FIG. 12 shows another separation system that may be employed for usewith systems and methods of the present disclosure;

FIG. 13 shows a heat recovery steam generator system;

FIG. 14 shows an example of an OCM system that produces power;

FIG. 15 shows an example of an OCM process with fresh ethane feed and nosales gas export;

FIG. 16 shows an example of an ethane skimmer implementation of OCM;

FIG. 17 shows a system comprising an existing natural gas liquids(NGL)/gas processing plant that has been retrofitted with an oxidativecoupling of methane (OCM) system for small scale and world scale olefinproduction (e.g., ethylene production);

FIG. 18 shows an example of integration of OCM with an ethylene plant.

FIG. 19 shows an example of integration of an OCM process with a naphthacracker;

FIG. 20 shows a computer system that is programmed or otherwiseconfigured to regulate OCM reactions;

FIG. 21 shows a schematic overview of an implementation of OCM;

FIG. 22 shows a photograph of a formed OCM catalyst;

FIG. 23 shows a scanning electron micrograph (SEM) of an OCM catalyst;

FIG. 24 shows another SEM of an OCM catalyst;

FIG. 25 shows an example of a temperature profile of an OCM reactor;

FIG. 26 shows a process flow diagram of a portion of an implementationof OCM;

FIG. 27 shows a process flow diagram of a portion of an implementationof OCM;

FIG. 28 shows a process flow diagram of a portion of an implementationof OCM;

FIG. 29 shows a process flow diagram of a portion of an implementationof OCM;

FIG. 30 shows a process flow diagram of a portion of an implementationof OCM; and

FIG. 31 shows a process flow diagram of a portion of an implementationof OCM.

DETAILED DESCRIPTION

While various embodiments of the invention have been shown and describedherein, it will be obvious to those skilled in the art that suchembodiments are provided by way of example only. Numerous variations,changes, and substitutions may occur to those skilled in the art withoutdeparting from the invention. It should be understood that variousalternatives to the embodiments of the invention described herein may beemployed.

The term “higher hydrocarbon,” as used herein, generally refers to ahigher molecular weight and/or higher chain hydrocarbon. A higherhydrocarbon can have a higher molecular weight and/or carbon contentthat is higher or larger relative to starting material in a givenprocess (e.g., OCM or ETL). A higher hydrocarbon can be a highermolecular weight and/or chain hydrocarbon product that is generated inan OCM or ETL process. For example, ethylene is a higher hydrocarbonproduct relative to methane in an OCM process. As another example, a C₃₊hydrocarbon is a higher hydrocarbon relative to ethylene in an ETLprocess. As another example, a C₅₊ hydrocarbon is a higher hydrocarbonrelative to ethylene in an ETL process. In some cases, a higherhydrocarbon is a higher molecular weight hydrocarbon.

The term “OCM process,” as used herein, generally refers to a processthat employs or substantially employs an oxidative coupling of methane(OCM) reaction. An OCM reaction can include the oxidation of methane toa higher hydrocarbon and water, and involves an exothermic reaction. Inan OCM reaction, methane can be partially oxidized and coupled to formone or more C₂₊ compounds, such as ethylene. In an example, an OCMreaction is 2CH₄+O₂→C₂H₄+2H₂O. An OCM reaction can yield C₂₊ compounds.An OCM reaction can be facilitated by a catalyst, such as aheterogeneous catalyst. Additional by-products of OCM reactions caninclude CO, CO₂, H₂, as well as hydrocarbons, such as, for example,ethane, propane, propene, butane, butene, and the like.

The term “non-OCM process,” as used herein, generally refers to aprocess that does not employ or substantially employ an oxidativecoupling of methane reaction. Examples of processes that may be non-OCMprocesses include non-OCM hydrocarbon processes, such as, for example,non-OCM processes employed in hydrocarbon processing in oil refineries,a natural gas liquids separations processes, steam cracking of ethane,steam cracking or naphtha, Fischer-Tropsch processes, and the like.

The terms “C₂₊” and “C²⁻ compound,” as used herein, generally refer to acompound comprising two or more carbon atoms. For example, C²⁻ compoundsinclude, without limitation, alkanes, alkenes, alkynes and aromaticscontaining two or more carbon atoms. C₂₊ compounds can includealdehydes, ketones, esters and carboxylic acids. Examples of C₂₊compounds include ethane, ethene, acetylene, propane, propene, butane,and butene.

The term “non-C₂₊ impurities,” as used herein, generally refers tomaterial that does not include C₂₊ compounds. Examples of non-C₂₊impurities, which may be found in certain OCM reaction product streams,include nitrogen (N₂), oxygen (O₂), water (H₂O), argon (Ar), hydrogen(H₂) carbon monoxide (CO), carbon dioxide (CO₂) and methane (CH₄).

The term “small scale,” as used herein, generally refers to a systemthat generates less than or equal to about 250 kilotons per annum (KTA)of a given product, such as an olefin (e.g., ethylene).

The term “world scale,” as used herein, generally refers to a systemthat generates greater than about 250 KTA of a given product, such as anolefin (e.g., ethylene). In some examples, a world scale olefin systemgenerates at least about 1000, 1100, 1200, 1300, 1400, 1500, or 1600 KTAof an olefin.

The term “item of value,” as used herein, generally refers to money,credit, a good or commodity (e.g., hydrocarbon). An item of value can betraded for another item of value.

OCM Processes

In an OCM process, methane (CH₄) reacts with an oxidizing agent over acatalyst bed to generate C₂₊ compounds. For example, methane can reactwith oxygen over a suitable catalyst to generate ethylene, e.g.,2CH₄+O₂→C₂H₄+2H₂O (See, e.g., Zhang, Q., Journal of Natural Gas Chem.,12:81, 2003; Olah, G. “Hydrocarbon Chemistry”, Ed. 2, John Wiley & Sons(2003)). This reaction is exothermic (ΔH=−67 kcals/mole) and hastypically been shown to occur at very high temperatures (e.g., >450° C.or >700° C.). Non-selective reactions that can occur include (a)CH₄+2O₂→CO₂+2H₂O and (b) CH₄+½O₂→CO+2H₂. These non-selective reactionsare also exothermic, with reaction heats of −891 kJ/mol and −36 kJ/molrespectively. The conversion of methane to COx products is undesirabledue to both heat management and carbon efficiency concerns.

Experimental evidence suggests that free radical chemistry is involved.(Lunsford, J. Chem. Soc., Chem. Comm., 1991; H. Lunsford, Angew. Chem.,Int. Ed. Engl., 34:970, 1995). In the reaction, methane (CH₄) isactivated on the catalyst surface, forming methyl radicals which thencouples in the gas phase to form ethane (C₂H₆), followed bydehydrogenation to ethylene (C₂H₄). The OCM reaction pathway can have aheterogeneous/homogeneous mechanism, which involves free radicalchemistry. Experimental evidence has shown that an oxygen active site onthe catalyst activates the methane, removes a single hydrogen atom andcreates a methyl radical. Methyl radicals react in the gas phase toproduce ethane, which is either oxidative or non-oxidativelydehydrogenated to ethylene. The main reactions in this pathway can be asfollows: (a) CH₄+O⁻→CH₃*+OH; (b) 2CH₃*→C₂H₆; (c) C₂H₆+O⁻→C₂H₄+H₂O. Insome cases, to improve the reaction yield, ethane can be introduceddownstream of the OCM catalyst bed and thermally dehydrogenated via thefollowing reaction: C₂H₆→C₂H₄+H₂. This reaction is endothermic (ΔH=−144kJ/mol), which can utilize the exothermic reaction heat produced duringmethane conversion. Combining these two reactions in one vessel canincrease thermal efficiency while simplifying the process.

Several catalysts have shown activity for OCM, including various formsof iron oxide, V₂O₅, MoO₃, Co₃O₄, Pt—Rh, Li/ZrO₂, Ag—Au, Au/Co₃O₄,Co/Mn, CeO₂, MgO, La₂O₃, Mn₃O₄, Na₂WO₄, MnO, ZnO, and combinationsthereof, on various supports. A number of doping elements have alsoproven to be useful in combination with the above catalysts.

Since the OCM reaction was first reported over thirty years ago, it hasbeen the target of intense scientific and commercial interest, but thefundamental limitations of the conventional approach to C—H bondactivation appear to limit the yield of this attractive reaction underpractical operating conditions. Specifically, numerous publications fromindustrial and academic labs have consistently demonstratedcharacteristic performance of high selectivity at low conversion ofmethane, or low selectivity at high conversion (J. A. Labinger, Cat.Lett., 1:371, 1988). Limited by this conversion/selectivity threshold,no OCM catalyst has been able to exceed 20-25% combined C₂ yield (i.e.,ethane and ethylene), and more importantly, all such reported yieldsoperate at extremely high temperatures (>800° C.). Novel catalysts andprocesses have been described for use in performing OCM in theproduction of ethylene from methane at substantially more practicabletemperatures, pressures and catalyst activities. These are described inU.S. Patent Publication Nos. 2012/0041246, 2013/0023079, 2013/165728,2014/0012053 and 2014/0018589, the full disclosures of each of which areincorporated herein by reference in its entirety for all purposes.

An OCM reactor can include a catalyst that facilitates an OCM process.The catalyst may include a compound including at least one of an alkalimetal, an alkaline earth metal, a transition metal, and a rare-earthmetal. The catalyst may be in the form of a honeycomb, packed bed, orfluidized bed. In some embodiments, at least a portion of the OCMcatalyst in at least a portion of the OCM reactor can include one ormore OCM catalysts and/or nanostructure-based OCM catalyst compositions,forms and formulations described in, for example, U.S. PatentPublication Nos. 2012/0041246, 2013/0023709, 2013/0158322, 2013/0165728,2014/0181877 and 2014/0274671, each of which is entirely incorporatedherein by reference. Using one or more nanostructure-based OCM catalystswithin the OCM reactor, the selectivity of the catalyst in convertingmethane to desirable C₂₊ compounds can be about 10% or greater; about20% or greater; about 30% or greater; about 40% or greater; about 50% orgreater; about 60% or greater; about 65% or greater; about 70% orgreater; about 75% or greater; about 80% or greater; or about 90% orgreater.

In some cases, the selectivity of an OCM process in converting methaneto desirable C²⁻ compounds is from about 20% to about 90%. In somecases, the selectivity of an OCM process in converting methane todesirable C₂₊ compounds is from about 30% to about 90%. In some cases,the selectivity of an OCM process in converting methane to desirable C₂₊compounds is from about 40% to about 90%. In some cases, the selectivityof an OCM process in converting methane to desirable C₂₊ compounds isfrom about 50% to about 90%. In some cases, the selectivity of an OCMprocess in converting methane to desirable C₂₊ compounds is from about60% to about 90%. In some cases, the selectivity of an OCM process inconverting methane to desirable C₂₊ compounds is from about 70% to about90%. In some cases, the selectivity of an OCM process in convertingmethane to desirable C₂₊ compounds is from about 80% to about 90%. Theselectivity of an OCM process in converting methane to desirable C₂₊compounds can be about 10% or greater; about 20% or greater; about 30%or greater; about 40% or greater; about 50% or greater; about 60% orgreater; about 65% or greater; about 70% or greater; about 75% orgreater; about 80% or greater; or about 90% or greater.

An OCM process can be characterized by a methane conversion fraction.For example, from about 5% to about 50% of methane in an OCM processfeed stream can be converted to higher hydrocarbon products. In somecases, about 5%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, or 50% ofmethane in an OCM process feed stream is converted to higher hydrocarbonproducts. In some cases, at least about 5%, 10%, 15%, 20%, 25%, 30%,35%, 40%, 45%, or 50% of methane in an OCM process feed stream isconverted to higher hydrocarbon products. In some cases, at most about5%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, or 50% of methane in an OCMprocess feed stream is converted to higher hydrocarbon products.

An OCM reactor can be sized, shaped, configured, and/or selected basedupon the need to dissipate the heat generated by the OCM reaction. Insome embodiments, multiple, tubular, fixed bed reactors can be arrangedin parallel to facilitate heat removal. At least a portion of the heatgenerated within the OCM reactor can be recovered, for example the heatcan be used to generate high temperature and/or pressure steam. Whereco-located with processes requiring a heat input, at least a portion ofthe heat generated within the OCM reactor may be transferred, forexample, using a heat transfer fluid, to the co-located processes. Whereno additional use exists for the heat generated within the OCM reactor,the heat can be released to the environment, for example, using acooling tower or similar evaporative cooling device. In someembodiments, an adiabatic fixed bed reactor system can be used and thesubsequent heat can be utilized directly to convert or crack alkanesinto olefins. In some embodiments, a fluidized bed reactor system can beutilized. OCM reactor systems useful in the context of the presentinvention may include those described in, for example, U.S. patentapplication Ser. No. 13/900,898 (filed May 23, 2013), which isincorporated herein by reference in its entirety for all purposes.

The methane feedstock for an OCM reactor can be provided from varioussources, such as non-OCM processes. In an example, methane is providedthrough natural gas, such as methane generated in a natural gas liquids(NGL) system.

Methane can be combined with a recycle stream from downstream separationunits prior to or during introduction into an OCM reactor. In the OCMreactor, methane can catalytically react with an oxidizing agent toyield C₂₊ compounds. The oxidizing agent can be oxygen (O₂), which maybe provided by way of air or enriched air. Oxygen can be extracted fromair, for example, in a cryogenic air separation unit.

To carry out an OCM reaction in conjunction with some catalytic systems,the methane and oxygen containing gases generally need to be brought upto appropriate reaction temperatures, e.g., typically in excess of 450°C. for some catalytic OCM processes, before being introduced to thecatalyst, in order to allow initiation of the OCM reaction. Once thatreaction begins or “lights off,” then the heat of the reaction istypically sufficient to maintain the reactor temperature at appropriatelevels. Additionally, these processes may operate at a pressure aboveatmospheric pressure, such as in the range of about 1 to 30 bars(absolute).

In some cases, the oxidizing agent and/or methane are pre-conditionedprior to, or during, the OCM process. The reactant gases can bepre-conditioned prior to their introduction into a catalytic reactor orreactor bed, in a safe and efficient manner. Such pre-conditioning caninclude (i) mixing of reactant streams, such as a methane-containingstream and a stream of an oxidizing agent (e.g., oxygen) in an OCMreactor or prior to directing the streams to the OCM reactor, (ii)heating or pre-heating the methane-containing stream and/or the streamof the oxidizing agent using, for example, heat from the OCM reactor, or(iii) a combination of mixing and pre-heating. Such pre-conditioning canminimize, if not eliminate auto-ignition of methane and the oxidizingagent. Systems and methods for pre-conditioning reactant gases aredescribed in, for example, U.S. patent application Ser. No. 14/553,795,filed Nov. 25, 2014, which is entirely incorporated herein by reference.

A wide set of competitive reactions can occur simultaneously orsubstantially simultaneously with the OCM reaction, including totalcombustion of both methane and other partial oxidation products. An OCMprocess can yield C₂₊ compounds as well as non-C₂₊ impurities. The C₂₊compounds can include a variety of hydrocarbons, such as hydrocarbonswith saturated or unsaturated carbon-carbon bonds. Saturatedhydrocarbons can include alkanes, such as ethane, propane, butane,pentane and hexane. Unsaturated hydrocarbons may be more suitable foruse in downstream non-OCM processes, such as the manufacture ofpolymeric materials (e.g., polyethylene). Accordingly, at least some,all or substantially all of the alkanes in the C₂₊ compounds may beconverted to compounds with unsaturated moieties, such as alkenes,alkynes, alkoxides, ketones, including aromatic variants thereof.

Once formed, C₂₊ compounds can be subjected to further processing togenerate desired or otherwise predetermined chemicals. In somesituations, the alkane components of the C₂₊ compounds are subjected tocracking in an OCM reactor or a reactor downstream of the OCM reactor toyield other compounds, such as alkenes (or olefins). See, e.g., U.S.patent application Ser. No. 14/553,795, filed Nov. 25, 2014, which isentirely incorporated herein by reference.

The OCM effluent can be cooled after the conversion to ethylene hastaken place. The cooling can take place within a portion of the OCMreactor and/or downstream of the OCM reactor (e.g., using at least about1, 2, 3, 4, 5 or more heat exchangers). In some cases, a heat exchangeris a heat recovery steam generator (HRSG). Cooling the OCM effluentsuitably rapidly and to a suitably low temperature can preventundesirable reactions from occurring with the OCM effluent, including,but not limited to the formation of coke or other by-products.

In some embodiments, the OCM effluent is cooled to a target temperatureof equal to or less than about 700° C., equal to or less than about 650°C., equal to or less than about 600° C., equal to or less than about550° C., equal to or less than about 500° C., equal to or less thanabout 450° C., equal to or less than about 400° C., equal to or lessthan about 350° C., equal to or less than about 300° C., equal to orless than about 250° C., or equal to or less than about 200° C. In somecases, the OCM effluent is cooled to the target temperature within about1 second, within about 900 milliseconds (ms), within about 800 ms,within about 700 ms, within about 600 ms, within about 500 ms, withinabout 400 ms, within about 300 ms, within about 200 ms, within about 100ms, within about 80 ms, within about 60 ms, within about 40 ms, orwithin about 20 ms of the production of the desired or otherwisepredetermined concentration of ethylene in the OCM reaction.

In some situations, an OCM system generates ethylene that can besubjected to further processing to generate different hydrocarbons withthe aid of conversion processes (or systems). Such a process can be partof an ethylene to liquids (ETL) process flow comprising one or more OCMreactors, separations units, and one or more conversion processes forgenerating higher molecular weight hydrocarbons. The conversionprocesses can be integrated in a switchable or selectable manner inwhich at least a portion or all of the ethylene containing product canbe selectively directed to 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or moredifferent process paths to yield as many different hydrocarbon products.An example OCM and ETL (collectively “OCM-ETL” herein) is provided inU.S. Patent Publication No. 2014/0171707, filed on Dec. 6, 2013, whichis entirely incorporated herein by reference.

OCM Processes for Producing Olefins

An aspect of the present disclosure provides OCM processes that areconfigured to generate olefins (or alkenes), such as ethylene, propylene(or propene), butylenes (or butenes), etc. An OCM process can be astandalone process or can be integrated in a non-OCM process, such as anatural gas liquids (NGL or NGLs) or gas processing system.

Reference will now be made to the figures, wherein like numerals referto like parts throughout. It will be appreciated that the figures andfeatures therein are not necessarily drawn to scale. In the figures, thedirection of fluid flow between units is indicated by arrows. Fluid maybe directed from one unit to another with the aid of valves and a fluidflow system. In some examples, a fluid flow system can includecompressors and/or pumps, as well as a control system for regulatingfluid flow, as described elsewhere herein.

FIG. 1 is a block flow diagram of a system 100 that is configured togenerate olefins, such as ethylene. The system 100 can be a small scaleor world scale system. The system 100 comprises an OCM sub-system 101that can include one or more OCM units in series and/or parallel. TheOCM sub-system 101 can include one or more post-bed cracking (PBC) unitsfor generating olefins (e.g., ethylene) from alkanes (e.g., ethaneand/or propane). A PBC unit can be disposed downstream of an OCM unit.The OCM unit and PBC unit can be situated in separate reactor, orincluded in the same reactor (e.g., a packed bed for OCM disposedupstream of a PBC unit in the same reactor). In some cases, anintegrated OCM unit and PBC unit may be collectively referred to as anOCM reactor.

The OCM sub-system 101 can accept ethane and an oxidizing agent (e.g.,O₂). In the illustrated example, the OCM sub-system 101 accepts ethanefrom ethane stream 102 and oxygen (O₂) from oxygen stream 103. Ethanecan be injected into the OCM sub-system 101 at a PBC unit of the OCMsub-system 101. Oxygen can be provided by way of air or provided from anoxygen generation unit, such as a cryogenic unit that accepts air andgenerates individual O₂ and N₂ streams, or by O₂ pipeline. The OCMsub-system 101 also accepts methane from C₁ recycle stream 104 andethane from C₂ recycle stream 105.

In an OCM unit of the OCM sub-system 101, methane can be catalyticallyreacted with oxygen in an OCM process to generate an OCM effluent stream106 comprising C₂₊ compounds and non-C₂₊ impurities. The OCM effluentstream 106 can be directed to a PBC unit of the OCM sub-system 101 toconvert one or more alkanes in the OCM effluent stream 106 to alkenes.Next, the OCM effluent stream 106 can be directed to a process gascompressor (PGC) unit 107. Natural gas (NG) is directed along an NG feed108 to a sulfur removal unit 109, which can remove sulfur-containingchemicals from the NG feed 108 to yield a sulfur-free methane feed 124to the PGC unit 107. As an alternative, the sulfur removal unit 109 canbe excluded if the concentration of Sulfur in the incoming natural gasfeed stream is very low and acceptable for the OCM process. As anotheralternative, the methane feed 124 can be provided from other sourcesthat may not be natural gas. In some cases, for example if the naturalgas feed has a considerable quantity of hydrogen, it can be routed tothe methanation unit. From the PGC unit 107, the OCM effluent can bedirected to CO₂ removal unit 110, which can remove CO₂ from the OCMeffluent. At least a portion of the removed CO₂ can be directed to amethanation unit 111 along a CO₂ stream 112. At least a portion of theremoved CO₂ can be directed along CO₂ stream 113 for other users, suchas, for example, storage or purged from the CO₂ removal unit 110. Insome cases, the CO₂ removal system can comprise a pressure swingadsorption (PSA) unit; in other cases, the CO₂ removal system can bebased on any other membrane separation process. The effluent from theCO₂ removal unit can be treated to remove water. The water removalsystem can be a molecular sieve dryer, or a series of dryers (not shownin the figure).

Next, the OCM effluent can be directed from the CO₂ removal unit 110 toa demethanizer (also “de-methanizer” herein) unit 114, which canseparate methane from higher molecular weight hydrocarbons (e.g.,acetylene, ethane and ethylene). The separated (or recovered) methanecan be directed to the methanation unit 111 along a C₁ recycle stream115. Alternatively, or in addition to, the separated methane can bedirected to the OCM sub-system 101. A purge stream 123 can be directedout of the demethanizer unit 114, which is a portion of stream 115. Thepurge stream can contain methane and inert gas, such as, e.g., N₂, He orAr. The purge flow rate may be sufficient such that the inert gas willnot accumulate in the system. The purge stream may be required to removeinert gas(es) that are built-up in the recycle loop.

The methanation unit 111 can generate methane from CO, CO₂ and H₂.Methane generated in the methanation unit 111 can be directed to the OCMsub-system 101 along C₁ recycle stream 104. The methanation unit 111 canbe as described elsewhere herein.

In some examples, the demethanizer unit 114 includes one or moredistillations columns in series and/or parallel. A serial configurationcan enable the separation of different components. A parallelconfiguration can enable separation of a fluid stream of greatervolumetric flow rate. In an example, the demethanizer unit 114 comprisesa distillation column and is configured to separate methane from C²⁻compounds in the OCM effluent stream. The demethanizer unit 114 can beas described elsewhere herein.

Higher molecular weight hydrocarbons separated from methane in thedemethanizer unit 114 can be directed to an acetylene conversion unit116 along stream 117. The acetylene conversion unit 116 can reactacetylene (C₂H₂) in the OCM effluent with H₂ to generate ethylene. Theacetylene conversion unit 116 in some cases can react other alkenes withH₂ to generate alkanes, such as ethane. The acetylene conversion unit116 can be a hydrogenation reactor. The OCM effluent stream can then bedirected from the acetylene conversion unit 116 to a deethanizer (also“de-ethanizer” herein) unit 118 along stream 119. The deethanizer unit118 can separate C₂ compounds (e.g., ethane and ethylene) from C₃₊compounds (e.g., propane and propylene). Separated C₃₊ compounds canleave the deethanizer unit 118 along stream 120. C₂ compounds from thedeethanizer unit 118 can be directed to a C₂ splitter 121, which canseparate ethane from ethylene. The C₂ splitter 121 can be a distillationcolumn. Recovered ethylene can be directed along stream 122 and employedfor downstream use.

OCM effluent can be characterized by a particular ethane-to-ethyleneratio or range of ratios. For example, OCM effluent can have anethane-to ethylene-ratio from about 3:1 to about 1:20. OCM effluent canhave an ethane-to-ethylene ratio of about 3:1, 2:1, 1:1, 1:2, 1:3, 1:4,1:5, 1:6, 1:7, 1:8, 1:9, 1:10, 1:11, 1:12, 1:13, 1:14, 1:15, 1:16, 1:17,1:18, 1:19, or 1:20.

OCM effluent can be characterized by a particular ratio or range ofratios of hydrocarbon compounds with three or more carbon atoms (“C₃₊compounds”) to C₂ compounds. For example, OCM effluent can have a C₃₊compounds-to-C₂ compounds ratio from about 0 to about 1:3. OCM effluentcan have a C₃₊ compounds-to-C₂ compounds ratio of about 0, 1:1000,1:100, 1:90, 1:80, 1:70, 1:60, 1:50, 1:40, 1:30, 1:20, 1:19, 1:18, 1:17,1:16, 1:15, 1:14, 1:13, 1:12, 1:11, 1:10, 1:9, 1:8, 1:7, 1:6, 1:5, 1:4,or 1:3.

OCM effluent can be characterized by a particular acetylene-to-ethyleneratio or range of ratios. For example, OCM effluent can have anacetylene-to-ethylene ratio from about 0 to about 1:1. OCM effluent canhave an acetylene-to-ethylene ratio of about 0, 1:1000, 1:100, 1:90,1:80, 1:70, 1:60, 1:50, 1:40, 1:30, 1:20, 1:19, 1:18, 1:17, 1:16, 1:15,1:14, 1:13, 1:12, 1:11, 1:10, 1:9, 1:8, 1:7, 1:6, 1:5, 1:4, 1:3, 1:2, or1:1.

OCM effluent can be characterized by a particular CO-to-CO₂ ratio orrange of ratios. For example, OCM effluent can have a CO-to-CO₂ ratiofrom about 0 to about 2:1. OCM effluent can have a CO-to CO₂ ratio ofabout 0, 1:1000, 1:100, 1:90, 1:80, 1:70, 1:60, 1:50, 1:40, 1:30, 1:20,1:19, 1:18, 1:17, 1:16, 1:15, 1:14, 1:13, 1:12, 1:11, 1:10, 1:9, 1:8,1:7, 1:6, 1:5, 1:4, 1:3, 1:2, 1:1, or 2:1.

Systems, methods, and processes of the present disclosure, such as thosefor OCM-ETL, operate on feedstocks with particular ethane-to-methaneratios. For example, a system feedstock can have an ethane-to-methaneratio from about 0 to about 1:3. A system feedstock can have anethane-to-methane ratio of about 0, 1:1000, 1:100, 1:90, 1:80, 1:70,1:60, 1:50, 1:40, 1:30, 1:20, 1:19, 1:18, 1:17, 1:16, 1:15, 1:14, 1:13,1:12, 1:11, 1:10, 1:9, 1:8, 1:7, 1:6, 1:5, 1:4, or 1:3.

The systems of the present disclosure, such as the systems of FIGS. 1-2,can be suited for the production of any olefin, such as, for example,ethylene. Thus, the systems above and elsewhere herein are not limitedto ethylene but may be configured to generate other olefins, such aspropylene, butenes, pentene, or other alkenes.

Post-bed cracking (PBC) units that may be suitable for use with systemsof the present disclosure, such as the systems of FIGS. 1-2, aredescribed in, for example, U.S. patent application Ser. No. 14/553,795,filed Nov. 25, 2014, which is entirely incorporated herein by reference.

The systems of FIGS. 1 and 17 may employ different unit operations forsmall scale and world scale olefin production (e.g., ethyleneproduction). The present disclosure provides non-limiting example unitoperations and process flows for various units that may be employed foruse with the systems of FIGS. 1 and 17.

Subsystems in an OCM Unit

FIGS. 2-4 show various sub-systems that may be suitable for use in asystem that is configured for the production of ethylene or otherolefins at small scale. Any suitable gas processing technology (e.g.,recycle split gas (RSV) or other gas processing technologies may beimplemented in the extraction unit to separate methane from NGLs or C₂+components with an economic recovery that may be at least about 70%,80%, 90%, 91%, 92%, 93%, 94%, 95%, 96%, 97%, 98%, or 99%. FIG. 2A showsan OCM reactor 201 that is configured to generate C₂₊ compounds fromoxygen (O₂) and methane, which can be directed into the OCM reactor 201along an oxygen stream 202 and a methane stream 203, respectively.Ethane can be directed into the OCM reactor 201 along an ethane recyclestream 227. The streams 202, 203 and 227 can each be pre-conditionedprior to injection into the OCM reactor 201. Such pre-conditioning caninclude pre-heating and/or pre-mixing. For example, the methane stream203 can be mixed with the oxygen stream 202 prior to injection into theOCM reactor 201.

The OCM reactor 201 can include an OCM unit upstream of a PBC unit. TheOCM unit can include one or more catalysts for catalyzing an OCMreaction using oxygen and methane directed into the OCM reactor 201along streams 202 and 203, respectively. The OCM reactor 201 cangenerate an OCM effluent comprising C₂₊ compounds and non-C₂₊impurities. The OCM effluent can be directed along an OCM effluentstream 204 from the OCM reactor 201 to a plurality of heat exchangers,shown in the figure as a single heat recovery block 205, which transfersheat from the OCM effluent stream 204 to the methane stream 203 topre-heat the methane stream 203. The OCM effluent stream 204 can bedirected to a separator 210, which can remove water from the OCMeffluent stream 204 and provide a water stream 211 comprising water andan OCM effluent stream 212 comprising C₂₊ compounds and non-C₂₊impurities. The concentration of water in the stream 212 may besubstantially reduced in relation to the concentration of water in theOCM effluent stream 204.

With continued reference to FIG. 2A, CO and/or CO₂ in a recycle stream206 from downstream processes (see below) are directed into amethanation system 207 and used to generate methane in a methanationprocess, as described elsewhere herein. Methane generated in themethanation system 207 is directed along the methane stream 203 into theOCM reactor 201. Recycle methane (C₁) is directed along C₁ recyclestream 208 into the methanation system 207 and combined with the methaneformed in the methanation system 207. The C₁ recycle stream can bepre-heated in a heat exchanger prior to introduction into themethanation system 207.

With reference to FIG. 2B, the OCM effluent stream 212 is directed intothe compression and treatment section. The OCM effluent 212 is routed toa quench tower 213 where the OCM effluent gases are quenched with acooling medium and any process condensates are condensed and removed.The cooled OCM effluent is then fed to the compressor unit 214, whichcan comprise of a single or multiple stages of compression. Thecompressor unit 214 can also comprise inter-stage coolers and separatorvessels which raise the pressure of the OCM effluent stream 212 (e.g.,by a factor of from about 2.5:1 to 4:1) and remove water from the OCMeffluent stream 212. The condensate streams from the separator vesselsfrom 214 are routed along 215 as the net condensate removed from theunit. The pressurized OCM effluent stream 216 (which includes C₂₊compounds) can be mixed with methane from stream 228 (e.g., natural gasstream) and subsequently directed to a CO2 removal system 217 forremoving CO₂ from the OCM effluent stream 216. The CO2 removal system217 can be an amine system, a membrane separation system or a causticbased wash system. The absorption system 217 comprises an absorptionunit 218, a regenerator 219 and a scrubber 220. The absorption unit 218can employ an aqueous solution of various alkylamines (also “amines”herein) to scrub CO₂ and H₂S from the OCM effluent stream 216. Examplesof amines include, without limitation, diethanolamine, monoethanolamine,methyldiethanolamine and diisopropanolamine. The resultant “rich” amineis then routed into the regenerator 219 (e.g., a stripper with areboiler) to produce regenerated or “lean” amine that is recycled forreuse in the absorption unit 218. The separated CO₂ can be purged 221 orrecycled 222 (e.g., to the methanation system 207 in stream 206).

The absorption unit 218 generates an OCM effluent stream that can have alow CO₂ content, which is directed to the scrubber 220. The scrubberremoves additional CO₂ and entrained solvents from the OCM effluentstream, using, for example, a sodium hydroxide stream that is directedthrough the scrubber 220 in a counter flow configuration. The OCMeffluent stream 223 is then directed from the scrubber 220 to aseparator 224, which removes water from the OCM effluent stream 223. Theremoved water is directed along stream 215. The OCM effluent stream isthen directed to dryers 225 and subsequently directed along stream 226.The dryers 225 can remove water from the OCM effluent stream. The OCMeffluent stream 223 may be cooled in a heat exchanger upon heat transferto a C₁ recycle stream, for example.

The system of FIGS. 2A and 2B may be employed for use with other systemsof the present disclosure. For example, the absorption system 217 ofFIG. 2B may be employed for use as the amine unit 110 of FIG. 1. Theseries of compressors 213, heat exchangers and separators of FIG. 2B maybe employed for use as the PGC 107 of FIG. 1.

FIG. 3 is a process flow diagram of a system 300 that can be used togenerate ethane and ethylene from acetylene (C₂H₂) and subsequentlyseparate ethane from ethylene. The sub-system 300 may be suitable forthe small scale production of ethylene. The system 300 can be employedfor use as the acetylene reactor 116, deethanizer 118 and C₂ splitter121 of FIG. 1. The system 300 comprises a hydrogenation reactor unit301, a first separation unit 302 and a second separation unit 303. Thefirst separation unit 302 and second separation unit 303 can bedistillation columns. The hydrogenation reactor unit 301 accepts astream 304 comprising H₂ and a stream 305 comprising C₂₊ compounds,which can include acetylene, and converts any acetylene in the stream305 to ethane and/or ethylene. The C₂₊ compounds are then directed instream 306 to the first separation unit 302, which separates C₃₊compounds (e.g., propane, propylene, butane, butene, etc.) from C₂compounds (ethane and/or ethylene) in the C₂₊ compounds. The firstseparation unit 302 may be referred to as a deethanizer The C₃₊compounds are directed along stream 307 and employed for downstream use.The C₂ compounds are directed to the second separation unit 303, whichseparates ethane from ethylene. The second separation unit 303 may bereferred to as a C₂ splitter. Ethane from the second separation unit 303is directed along stream 308 and ethylene is directed along stream 309.Ethane can be recycled, such as recycled to an OCM reactor. In someexamples, the ethane is recycled to a PBC unit of an OCM reactor.

The stream 304 may be directed to a pressure swing adsorption (PSA) unit(not shown) that is configured to separate H₂ from N₂. H₂ from thestream 304 may then be directed to the hydrogenation reactor 301. Thestream 304 may be provided by a separation system, such as the system1100 of FIG. 11. In situations in which a PSA is employed, the system300 may be suitable for use in world scale olefin production. For smallscale olefin production, the PSA may be precluded.

The acetylene hydrogenation reaction can be practiced over apalladium-based catalyst, such as those used to convert acetylene toethylene in conventional steam cracking (e.g., the PRICAT™ seriesincluding models PD 301/1, PD 308/4, PD 308/6, PD 508/1, PD 408/5, PD408/7 and PD 608/1, which may be commercially available as tablets orspheres supported on alumina). In some cases, the acetylenehydrogenation catalyst is a doped or modified version of a commerciallyavailable catalyst.

However, in some cases, applying an acetylene hydrogenation catalyst tothe OCM process that has been developed or optimized for another process(e.g., steam cracking separations and purification processes) can resultin operational issues and/or non-optimized performance. For example, insteam cracking, the acetylene conversion reactor can either be locatedon the front end (prior to cryogenic separations) or back end (aftercryogenic separations) of the process. In steam cracking, thesedifferences in running front end and back end typically have to do withthe ratio of hydrogen to acetylene present, the ethylene to acetyleneratio, and the non-ethylene olefin (e.g., butadiene) to acetylene ratio.All of these factors can impact the catalyst selectivity for formingethylene from acetylene, the lifetime and regeneration of the catalyst,green oil formation, specific process conditions for the reactor, andadditional hydrogen required for the reaction. These factors are alsodifferent between steam cracking versus OCM processes, therefore,provided herein is an acetylene hydrogenation catalyst that is designedto be used in an OCM process.

In OCM implementations, the chemical components going into the acetylenereactor can be different than for steam cracking. For example, OCMeffluent can include carbon monoxide and hydrogen. Carbon monoxide canbe undesirable because it can compete with the acetylene for the activesites on the hydrogenation catalyst and lead to lower activity of thecatalyst (e.g., by occupying those active sites). Hydrogen can bedesirable because it is needed for the hydrogenation reaction, howeverthat hydrogen is present in the OCM effluent in a certain ratio andadjusting that ratio can be difficult. Therefore, the catalyst describedherein provides the desired outlet concentrations of acetylene, desiredselectivity of acetylene conversion to ethylene, desired conversion ofacetylene, desired lifetime and desired activity in OCM effluent gas. Asused herein, “OCM effluent gas” generally refers to the effluent takendirectly from an OCM reactor, or having first undergone any number offurther unit operations such as changing the temperature, the pressure,or performing separations on the OCM reactor effluent. The OCM effluentgas can have CO, H₂ and butadiene.

In some embodiments, the catalyst decreases the acetylene concentrationbelow about 100 parts per million (ppm), below about 80 ppm, below about60 ppm, below about 40 ppm, below about 20 ppm, below about 10 ppm,below about 5 ppm, below about 3 ppm, below about 2 ppm, below about 1ppm, below about 0.5 ppm, below about 0.3 ppm, below about 0.1 ppm, orbelow about 0.05 ppm.

The concentration of acetylene can be reached in the presence of carbonmonoxide (CO). In some embodiments, the feed stream entering theacetylene hydrogenation reactor contains at least about 10%, at leastabout 9%, at least about 8%, at least about 7%, at least about 6%, atleast about 5%, at least about 4%, at least about 3%, at least about 2%,or at least about 1% carbon monoxide.

When used in an OCM process, the acetylene hydrogenation catalyst canhave a lifetime of at least about 6 months, at least about 1 year, atleast about 2 years, at least about 3 years, at least about 4 years, atleast about 5 years, at least about 6 years, at least about 7 years, atleast about 8 years, at least about 9 years, or at least about 10 years.

FIG. 4 is a process flow diagram of a sulfur removal system 400, whichcan be employed for use in removing sulfur-containing compounds from agas stream. The sulfur removal system 400 can be employed for use as thesulfur removal system 109 of FIG. 1, for example. The system 400 can beemployed for use in a system that is configured to generate small scaleethylene. The system 400 comprises a separation unit 401 for removingwater form a natural gas stream 402. Water is removed along stream 403.The natural gas stream with decreased water content is directed alongstream 404 to a heat exchanger 405, another optional heat exchanger 406and an absorption unit 408. The heat exchangers 405 and 406 raise thetemperature of the natural gas stream. The absorption unit removes H₂Sfrom the natural gas stream. This can provide a stream 409 comprisingmethane and having a substantially low sulfur and H₂O content. In someexamples, the stream 409 is directed to an OCM reactor. As analternative, or in addition to, the stream 409 can be directed to anatural gas pipeline.

In certain cases, depending on the concentration of sulfur compounds inthe natural gas feed stream, the sulfur removal unit can comprise one ormore hydrodesulfurization (hydrotreater) reactors to convert the sulfurcompounds to H2S, which is then subsequently removed by an amine system.

FIG. 5 shows a sulfur removal unit comprising a separation unit 501, ahydrogen feed stream 502, a natural gas stream 503, a flare header 504,a methane-containing stream 505, a heat exchanger 506, a heat recoverysteam generator (HRSG) system 507, a hydro treating unit 508, anabsorption unit 509, and a product stream 510. The separation unit 501is configured to remove water from the stream 503. Water removed fromthe stream 503 is directed to the flare header 504. The hydro treatingunit 508 generates H₂S from H₂ provided by the stream 502 any sulfur inthe stream 503. Any sulfur-containing compounds in the stream 503 andgenerated in the hydro treating unit 508 can be removed in theabsorption unit 509. The resulting product stream 510 can includemethane and substantially low concentrations of sulfur-containingcompounds, such as H₂S. In some examples, the product stream 510 can bedirected to an OCM reactor or a natural gas pipeline.

The HRSG system 507 is an energy recovery heat exchanger that recoversheat from the stream 505. The HRSG system 507 can produce steam that canbe used in a process (cogeneration) or used to drive a steam turbine(combined cycle). The HRSG unit 507 can be as described herein.

Methanation Systems

Oxidative coupling of methane (OCM) can convert natural gas to ethyleneand other longer hydrocarbon molecules via reaction of methane withoxygen. Given the operating conditions of OCM, side reactions caninclude reforming and combustion, which can lead to the presence ofsignificant amounts of H₂, CO and CO₂ in the OCM effluent stream. H₂content in the effluent stream can range between about 5% and about 15%,between about 1% and about 15%, between about 5% and about 10%, orbetween about 1% and about 5% (molar basis). The content of CO and CO₂can each range between about 1% and about 5%, between about 1% and about3%, or between about 3% and about 5% (molar basis). In some cases, theethylene and all the other longer hydrocarbon molecules contained in theeffluent stream are separated and purified to yield the final productsof the process. This can leave an effluent stream containing theunconverted methane, hydrogen, CO and CO₂ and several other compounds,including low amounts of the product themselves depending on theirrecovery rates.

In some cases, this effluent stream is recycled to the OCM reactor.However, if CO and H₂ are recycled to the OCM reactor along withmethane, they can react with oxygen to produce CO₂ and H₂O, causingvarious negative consequences to the process including, but not limitedto: (a) an increase of the natural gas feed consumption (e.g., because alarger portion of it may result in CO₂ generation instead of productgeneration); (b) a decrease of the OCM per-pass methane conversion(e.g., because a portion of the allowable adiabatic temperature increasemay be exploited by the H₂ and CO combustion reactions instead of theOCM reactions); and an increase of the oxygen consumption (e.g., becausesome of the oxygen feed may react with CO and H₂ instead of methane).

The effluent stream can be exported to a natural gas pipeline (e.g., tobe sold as sales gas into the natural gas infrastructure). Given thatspecifications can be in place for natural gas pipelines, theconcentrations of CO, CO₂ and H₂ in the effluent can need to be reducedto meet the pipeline requirements. The effluent stream may also be usedas a feedstock for certain processes that may require lowerconcentrations of H₂, CO and CO₂.

Therefore, it can be desirable to reduce the concentration of H₂, CO andCO₂ in the OCM effluent stream, upstream or downstream of the separationand recovery of the final products. This can be accomplished usingmethanation systems and/or by separating H₂ and CO from the effluentstream (e.g., using cryogenic separations or adsorption processes). Thedisclosure also includes separating CO₂ from the effluent stream usingCO₂ removal processes, such as chemical or physical absorption oradsorption or membranes. However, these separation processes can requiresignificant capital investments and can consume considerable amounts ofenergy, in some cases making an OCM-based process less economicallyattractive.

The present disclosure also provides systems and methods for reducingCO, CO₂ and H₂ concentration in a methane stream. Such compounds can bereacted to form methane in a methanation reaction.

An aspect of the present disclosure provides a methanation system thatcan be employed to reduce the concentration of CO, CO₂ and H₂ in a givenstream, such as an OCM product stream. This can advantageously minimizethe concentration of CO, CO₂ and H₂ in any stream that may be ultimatelyrecycled to an OCM reactor. The methanation system can be employed foruse with any system of the present disclosure, such as an OCM-ETL systemdescribed herein.

In a methanation system, CO reacts with H₂ to yield methane viaCO+3H₂→CH₄+H₂O. In the methanation system, CO₂ can react with H₂ toyield methane via CO₂+4H₂→CH₄+2H₂O. Such processes are exothermic(ΔH=−206 kJ/mol and −178 kJ/mol, respectively) and generate heat thatmay be used as heat input to other process units, such as heating an OCMreactor of a PBC reactor, or pre-heating reactants, such as methaneand/or an oxidizing agent (e.g., O2) prior to an OCM reaction. Themethanation reaction can take place in two or more reactors in series,in some cases with intercooling. In some situations, a methanationreactor can be implemented in tandem with an OCM reactor to increasecarbon efficiency.

In some cases, to limit the heat release per unit of flow of reactants,methanation can be conducted on streams that contain CO, CO₂, H₂ and asuitable carrier gas. The carrier gas can include an inert gas, such as,e.g., N₂, He or Ar, or an alkane (e.g., methane, ethane, propane and/orbutane). The carrier gas can add thermal heat capacity and significantlyreduce the adiabatic temperature increase resulting from the methanationreactions.

In some examples, methane and higher carbon alkanes (e.g., ethane,propane and butane) and nitrogen are employed as carrier gases in amethanation process. These molecules can be present in an OCM process,such as in an OCM product stream comprising C₂₊ compounds. Downstreamseparation units, such as a cryogenic separation unit, can be configuredto produce a stream that contains any (or none) of these compounds incombination with CO and H₂. This stream can then be directed to themethanation system.

A methanation system can include one or more methanation reactors andheat exchangers. CO, CO₂ and H₂ can be added along various streams tothe one or more methanation reactors. A compressor can be used toincrease the CO₂ stream pressure up to the methanation operatingpressure, which can be from about 2 bar (absolute) to 60 bar, or 3 barto 30 bar. CO₂ can be added to the inlet of the system in order tocreate an excess of CO₂ compared to the amount stoichiometricallyrequired to consume all the available H₂. This is done in order tominimize H₂ recycled to OCM.

Given the exothermicity of the methanation reactions, a methanationsystem can include various methanation reactors for performingmethanation. In some cases, a methanation reactor is an adiabaticreactor, such as an adiabatic fixed bed reactor. The adiabatic reactorcan be in one stage or multiple stages, depending, for example, on theconcentration of CO, CO₂ and H₂ in the feed stream to the methanationsystem. If multiple stages are used, inter-stage cooling can beperformed by either heat exchangers (e.g., a stage effluent can becooled against the feed stream or any other colder stream available inthe plant, such as boiler feed water) or quenching via cold shots, i.e.the feed stream is divided into multiple streams, with one stream beingdirected to the first stage while each of the other feed streams beingmixed with each stage effluent for cooling purposes. As an alternative,or in addition to, a methanation reactor can be an isothermal reactor.In such a case, reaction heat can be removed by the isothermal reactorby, for example, generating steam, which can enable a higherconcentration of CO, CO₂ and H₂ to be used with the isothermal reactor.Apart from adiabatic and isothermal reactors, other types of reactorsmay be used for methanation, such as fluidized bed reactors.

FIG. 6A shows an example methanation system 600. The system 600 may beused in OCM systems that are for small scale or world scale productionof ethylene or other olefins. The system 600 comprises a first reactor601, second reactor 602 and a heat exchanger 603. The first reactor 601and second reactor 602 can be adiabatic reactors. During use, a recyclestream 604 comprising methane, CO and H₂ (e.g., from a cryogenicseparation unit) is directed to the heat exchanger 603. In an example,the recycle stream 604 comprises between about 65% and 90% (molar basis)methane, between about 5% and 15% H₂, between 1% and 5% CO, betweenabout 0% and 0.5% ethylene, and the balance inert gases (e.g., N₂, Arand He). The recycle stream 604 can have a temperature from about 20° C.to 40° C., or 20° C. to 30° C., and a pressure from about 2 bar to 60bar (absolute), or 3 bar to 30 bar. The recycle stream 604 can begenerated by a separation unit downstream of an OCM reactor, such as acryogenic separation unit.

In the heat exchanger 603, the temperature of the recycle stream 604 isincreased to about 100° C. to 400° C., or 200° C. to 300° C. The heatedrecycle stream 604 is then directed to the first reactor 601. In thefirst reactor 601, CO and H₂ in the recycle stream 604 react to yieldmethane. This reaction can progress until all of the H₂ is depletedand/or a temperature approach to equilibrium of about 0 to 30° C., or 0to 15° C. is achieved. The methanation reaction in the first reactor 601can result in an adiabatic temperature increase of about 20° C. to 300°C., or 50° C. to 150° C.

Next, products from the first reactor, including methane and unreactedCO and/or H₂, can be directed along a first product stream to the heatexchanger 603, where they are cooled to a temperature of about 100° C.to 400° C., or 200° C. to 300° C. In the heat exchanger 603, heat fromthe first product stream 603 is removed and directed to the recyclestream 604, prior to the recycle stream 604 being directed to the firstreactor 601.

Next, a portion of the heated first product stream is mixed with a CO₂stream 605 to yield a mixed stream that is directed to the secondreactor 602. The CO₂ stream 605 can be generated by a separation unitdownstream of an OCM reactor, such as a cryogenic separation unit. Thiscan be the same separation unit that generated the recycle stream 604.

In the second reactor 602, CO and CO₂ react with H₂ to yield a secondproduct stream 606 comprising methane. The reaction(s) in the secondreactor 602 can progress until substantially all of the H₂ is depletedand/or a temperature approach to equilibrium of about 0 to 30° C., or 0to 15° C. is achieved. The proportions of CO, CO₂ and H₂ in the mixedstream can be selected such that the second product stream 606 issubstantially depleted in CO and H₂.

The first reactor 601 and the second reactor 602 can be two catalyticstages in the same reactor vessel or can be arranged as two separatevessels. The first reactor 601 and second reactor 602 can each include acatalyst, such as a catalyst comprising one or more of ruthenium,cobalt, nickel and iron. The first reactor 601 and second reactor 602can be fluidized bed or packed bed reactors. Further, although thesystem 600 comprises two reactors 601 and 602, the system 600 caninclude any number of reactors in series and/or in parallel, such as atleast 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 20, 30, 40, or 50 reactors.

Although the CO₂ stream 605 is shown to be directed to the secondreactor 602 and not the first reactor 601, in an alternativeconfiguration, at least a portion or the entire CO₂ stream 605 can bedirected to the first reactor 601. The proportions of CO, CO₂ and H₂ canbe selected such that the methanation product stream is substantiallydepleted in CO and H₂.

Methane generated in the system 600 can be employed for various uses. Inan example, at least a portion of the methane can be recycled to an OCMreactor (e.g., as part of an OCM-ETL system) to generate C₂₊ compounds,including alkenes (e.g., ethylene). As an alternative, or in additionto, at least a portion of the methane can be directed to a non-OCMprocess, such as a natural gas stream of a natural gas plant. As anotheralternative, or in addition to, at least a portion of the methane can bedirected to end users, such as along a natural gas pipeline.

FIG. 6B is a process flow diagram of an example of a methanation systemthat can be employed to generate ethylene. The system of FIG. 6B can beused in other systems of the present disclosure, such as the system 100of FIG. 1. The system comprises compressors 607 and 608, separationunits 609 and 610, and methanation reactors 611 and 612. The separationunits 609 and 610 can be quench towers, which may separate water from astream comprising CO and/or CO₂. During use, a stream 613 comprising COand/or CO₂ is directed to the compressor 607 and subsequently theseparator unit 609. In stream 614, CO and/or CO₂ along with H₂ aredirected to the methanation reactor 611 and are reacted to form methane,which, along with any excess CO, CO₂ and H₂, is subsequently directed tothe methanation reactor 612, where CO and/or CO₂ provided in stream 615is reacted with H₂ to form additional methane. The methane generated inthe methanation reactors 611 and 612 is directed along stream 616. Themethane in stream 616 can be, for example, recycled to an OCM reactor.

Use of methanation systems with OCM systems of the present disclosurecan reduce the quantity CO and/or CO₂ that are directed to theenvironment, which may advantageously decrease overall greenhouseemissions from such systems. In some examples, using a methanationsystem, the emission of CO and/or CO₂ from an OCM system can be reducedby at least about 0.01%, 0.1%, 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, 10%,20%, 30%, 40%, or 50%.

The methanation reaction can be practiced over a nickel-based catalyst,such as those used to produce SNG (Substitute Natural Gas or SyntheticNatural Gas) from syngas or used to purify streams containing CO and CO₂(e.g., to remove CO and CO₂ present in the make-up feed to an ammoniasynthesis unit). Examples of such catalysts include the KATALCO™ series(including models 11-4, 11-4R, 11-4M and 11-4MR) that may include nickelsupported on refractory oxides; the HTC series (including NI 500 RP 1.2)having nickel supported on alumina; and Type 146 having rutheniumsupported on alumina. Additional methanation catalysts can includemodels PK-7R and METH-134. The methanation catalyst can be tableted oran extruded. The shapes of such catalysts can be, for example,cylindrical, spherical, or ring structures, for or partial shapes and/orcombinations of shapes thereof. In some cases, ring structures areadvantageous due to their reduced pressure drop across the reactor bedrelative to cylindrical and spherical commercial forms. In some cases,the methanation catalyst is a doped or modified version of acommercially available catalyst.

In some cases, merely applying a methanation catalyst to the OCM processthat has been developed or optimized for another process (e.g., SNGproduction or gas purification) can result in operational problemsand/or non-optimal performance, including carbon formation (or coking)over the methanation catalyst. Coking can lead to de-activation of thecatalyst and, eventually, to loss of conversion through the methanationreactor, thus making the methanation process ineffective, severelylimiting the performances of the overall OCM-based process and,possibly, preventing the final products from achieving the requiredspecifications.

The selectivity and/or conversion produced by an existing and/orcommercially available methanation catalyst at a given process condition(e.g., gas-hourly space velocity, molar composition, temperature,pressure) may not be ideal for OCM implementations. For example, ammoniaplants can have between about 100 ppm and 1% CO with a molar excess ofH₂ (e.g., 2, 5, 10, 50, 100-fold or more excess) that drives equilibriumin favor of complete methanation. Methanation systems in ammonia plantshave a small temperature difference between inlet and outlet of theadiabatic methanation reactor (e.g., 20 to 30° C.) and can be sized forcatalyst lifetime. SNG production does not have a vast molar excess ofH₂ in some cases. Methanation in SNG processes can have an inlet versusoutlet temperature difference of greater than 100° C. and be performedin multiple stages. Furthermore, the purpose of methanation can bedifferent for OCM. Ammonia and SNG processes typically performmethanation primarily to eliminate CO and/or CO₂ (although H₂ can alsobe eliminated or substantially reduced in concentration), whilemethanation is performed in OCM processes primarily to eliminate H₂(although CO and/or CO₂ can also be eliminated or substantially reducedin concentration).

A methanation catalyst and/or catalytic process is described herein thatcan prevent or reduce carbon formation in the methanation reactor orother operational inefficiencies. The catalyst and/or catalytic processis achieved through any combination of: (a) removing chemical speciesthat can contribute to coke formation from the methanation inlet feed;(b) introducing chemical species into the methanation feed thateliminate or reduce the rate of coke formation; and (c) using themethanation catalyst described herein that reduces or eliminates cokeformation and/or is designed to operate at the process conditions of OCMeffluent or OCM process streams (e.g., gas-hourly space velocity, molarcomposition, temperature, pressure).

In some instances, the species present in the OCM effluent stream thatcan lead to carbon formation in the methanation reactor are removed orreduced in concentration using a separations or reactive process. Thetypical operating conditions of a methanation reactor can be at apressure between about 3 bar and about 50 bar and a temperature betweenabout 150° C. and about 400° C. Any hydrocarbon species containingcarbon-carbon double or triple bonds may be sufficiently reactive toform carbon deposits (i.e., coke). Examples of such species areacetylene, all olefins and aromatic compounds. Removal or significantreduction of these species can be achieved via different methodsincluding, but not limited to: (a) hydrogenation (i.e., reaction ofthese species with the hydrogen present in the effluent stream itself toproduce alkanes) over suitable catalysts prior to the methanationreactor; (b) condensation and separation of these species from methaneprior to the methanation reactor; (c) absorption or adsorption of thesespecies; (d) by utilizing suitable membranes; or (d) any combinationthereof.

In some embodiments, species are introduced into the methanation inletstream that eliminate or reduce the rate of carbon formation. Molecularspecies that can create a reducing atmosphere can be used to counteractan oxidation reaction and can therefore reduce the rate of carbonformation. Hydrogen and water are examples of these particular compoundsand can be added to the OCM effluent stream prior to methanation toincrease their concentration in the methanation reactor.

An aspect of the present disclosure provides a methanation catalyst foran OCM process. Coke formation is typically the product of surfacedriven reactions. Therefore, the methanation catalyst for OCM alters thelocal electronic environment around the active site of the catalyst.This can be done by changing the elemental composition (for example viapost-impregnation doping, or creating a new mixed metal of nickel andanother transition metal), morphology and structure (for example viasynthesizing the metal in a non-bulk form factor). Examples of suchsyntheses include; nanowires of the same material, nanoparticles coatedon a support, and vapor deposition of the active material on a supportmaterial. Additional modifications to the surface may result from postsynthetic processing steps, such as etching of the surface, oxidizingand reducing the metal to create a different surface reconstruction,calcination steps under different atmospheres (e.g., oxidizing orreducing), heating to achieve different crystal phases, and inducingdefect formation. The end result of the modifications of the methanationcatalyst is specifically designed to minimize carbon (coke) formation,while still effectively at conducting the methanation reactions.

The methanation process and/or methanation catalyst can operate with OCMproduct gas, either directly or after one or more heat exchangers orseparation operations. For example, the methanation feed stream can havethe following composition on a molar basis: CH₄ between about 65% andabout 90%; H₂ between about 5% and about 15%; CO between about 1% andabout 5% (molar basis); C₂H₄ between about 0% and about 0.5%; C₂H₂between about 0% and about 0.1%; and the balance inert gases such as N₂,Ar and He. The methanation feed stream typically has a temperature closeto ambient temperature and a pressure ranging between about 3 and about50 bar.

The methanation reaction can produce water and/or have water in themethanation effluent. In some cases, it is desirable to remove thiswater prior to recycling the methanation effluent to the OCM reactor.This can be accomplished by lowering the temperature of the methanationeffluent or performing any separation procedure that removes the water.In some embodiments, at least about 70%, at least about 80%, at leastabout 70%, at least about 90%, at least about 95%, or at least about 99%of the water is removed from the methanation effluent prior to the OCMreactor. Removing the water can increase the lifetime and/or performanceof the OCM catalyst.

A methanation process can be implemented in an OCM-based process usingadiabatic reactors. In an example, the process does not require amethanation catalyst specially designed or optimized for OCM. In thisexample, an OCM-based process is designed to produce ethylene fromnatural gas. In this case the product and recovery section of the OCMplant (e.g., a cryogenic unit) can be designed to separate ethylene andall other hydrocarbons from methane, CO and H₂ in the OCM effluent. Themixed stream that contains methane, CO and H₂ can be fed to themethanation section.

FIG. 7 shows an example of a methanation system for OCM. The methanationfeed stream 700 is first sent to a first heat exchanger 705 where itstemperature is increased to the methanation reactor inlet temperature,typically between 150° C. and 300° C. Steam 710 is injected immediatelydownstream of the first heat exchanger to increase water concentrationin the methanation feed stream. Then the heated stream is fed to a firstadiabatic reactor 715 where ethylene, acetylene and any otherhydrocarbon that presents carbon-carbon double or triple bonds arehydrogenated via reaction with the H₂ present in the stream.

The effluent from the first reactor 715 is then fed to a second reactor720, where CO reacts with H₂ until a certain approach to equilibrium isachieved, typically 0° C.-15° C. to equilibrium. The adiabatictemperature increase that results from CO methanation depends on theexact composition of the feed stream and is typically in the 50° C.-150°C. range.

The second reactor 720 effluent is then sent to the first heat exchanger705 and a second heat exchanger 725 where it is cooled down to atemperature below water condensation. The stream is then fed to a phaseseparator 730 where the condensed water 735 is separated from the vapors740 in order to minimize the water concentration in the vapors. It canbe important to remove water at this stage to optimize the conditionsfor the second methanation stage (water is a product of the methanationreaction and is no longer needed in the second stage because all carbonforming species have been either removed or converted at this point).

The vapor stream 740 is fed to a third heat exchanger 745 where it isheated up to the temperature required at the inlet of the thirdadiabatic reactor 750, which is the second methanation stage, typicallyoperated at between about 150° C. and about 300° C. Additional CO₂ 755produced in the process is mixed with effluent from the second reactor720 and fed to the third reactor 750. CO and CO₂ react with H₂ in thethird reactor 750 until a 0° C.-15° C. temperature approach toequilibrium is reached. Typically the amount of CO₂ that is added to thesecond reactor effluent is more than what may be stoichiometricallyrequired to consume all H₂, to push the equilibrium towards CO and H₂complete depletion.

The liquid stream from the phase separator 735 is re-injected into themethanation feed stream alongside the steam. Alternatively, it can befirst vaporized and then re-injected, or it can be sent to a watertreatment system for water recovery and purification.

The three reactors, 715, 720 and 750 or any combination of them can bephysically situated in the same vessel or can be arranged in separateindividual vessels. A portion or even all of the CO₂ addition may beperformed at the inlet of 715 or 720, depending on the type of catalystused in the two reactors.

OCM System Configurations

An OCM reactor system can comprise a single reactor or multiple reactorsin series and/or in parallel. For example, the OCM reactor systemincludes at least 2, 3, 4, or 5 OCM reactors in series. As anotherexample, the OCM reactor system includes at least 2, 3, 4, or 5 OCMreactors in parallel. As another example, the OCM reactor includes twoOCM reactors in parallel, both of which are downstream of another OCMreactor. In some cases, an OCM reactor system can comprise two reactors,three reactors, or four reactors in series. In certain embodiments, theabove mentioned number of reactors can be connected in parallel, or acombination thereof (e.g., mixed series and parallel). In addition,either one or more of the OCM reactor can contain a post-bed cracking(PBC) section as a part of the OCM reactor.

The OCM reaction is highly exothermic and the heat produced can be usedto generate steam. A heat recovery system can be designed so as to cooldown OCM reactor effluent to a temperature of less than or equal toabout 600° C., 500° C., 400° C., 300° C. or 200° C., or a temperaturebetween any two of these values (e.g., between 200° C. and 600° C., or300° C. and 500° C.), and to use that heat as process heat within theOCM unit, to heat boiler feed water (BFW) or steam, or for otherprocesses.

FIGS. 5, 8, and 13 show various sub-systems that may be suitable for usein a system that is configured for the production of ethylene at worldscale. With reference to FIG. 8A, a system 800 comprises a first OCMunit 801 and second OCM unit 802. The OCM units 801 and 802 are inseries—the second OCM unit 802 receives OCM effluent from the first OCMunit 801. Each OCM unit 801 and 802 includes and OCM reactor that isconfigured to react methane with an oxidizing agent to generate C₂₊compounds. One or both of the OCM units 801 and 802 can include a PBCreactor downstream of the OCM reactor. In the illustrated example, thesecond OCM unit 802 comprises a PBC reactor downstream of the OCMreactor of the second OCM unit 802.

During use, oxygen along stream 803 is directed into the OCM units 801and 802. Methane is directed to the first OCM unit 801 along stream 804.In the first OCM unit 801, methane and oxygen react in an OCM process toyield an OCM effluent stream 805 that is directed to a heat exchangerand subsequently the second OCM unit 802. The second OCM unit 802generates addition C₂₊ compounds from oxygen and any unreacted methanein the stream 805. In addition, the second OCM unit 802 accepts ethanealong stream 806 into the PCB reactor of the second OCM unit 802, andgenerates ethylene from the ethane. C₂₊ compounds generated in thesecond OCM unit 802, along with any non-C₂₊ impurities are directed outof the second OCM unit 802 along stream 807 to multiple heat exchangersand subsequently a separator 808, which removes water from the OCMeffluent stream. Water is directed out of the separator 808 along stream809, and C₂₊ compounds and any non-C₂₊ impurities are directed alongstream 810.

The system 800 further includes a methanation unit 811 that generatesmethane from H₂ and CO and/or CO₂. Methane generated in the methanationunit 811 is directed along stream 804 to the first OCM unit 801. Themethanation unit 811 may be as described elsewhere herein. Methane, suchas recycled methane, is directed along stream 812 through a heatexchanger and to the methanation unit 811. CO and/or CO₂ are directed tothe methanation unit 811 along stream 813.

The system 800 includes process stream that is used in the heatexchangers. Process steam is directed along stream 814 to various heatexchangers and is outputted along stream 815 and 816.

Although the system 800 includes two OCM units 801 and 802, the system800 can include any number of OCM units in series and parallel. An OCMunit can be an OCM reactor with an OCM catalyst. The system 800 caninclude at least 1, 2, 3, 4, 5, 6, 7, 8, 9, or 10 OCM units.

The stream 810 may be directed to a hydrogenation reactor and separationtrain to convert any acetylene in the stream 810 to ethane and/orethylene, and separate the ethane from ethylene. For world scaleethylene generation, the system 300 of FIG. 3 may be employed. A PSAunit may be used to separate H₂ from N₂ in a stream comprising H₂ andN₂.

With reference to FIG. 8B, the stream 810 is directed into a series ofcompressors 817 and separators 818, which raise the pressure of thestream 810 (e.g., by a factor of from about 2.5:1 to 4:1) and removewater from the stream 810. The separators may be quench towers. Waterremoved from a first of the separators 818 is directed along stream 819.The pressurized stream 820 (which includes C₂₊ compounds) can be mixedwith methane from stream 821 (e.g., natural gas stream or methane from amethanation unit) and subsequently directed to an absorption system 822for removing CO₂ from the stream 820. The absorption system 822 can bean amine system. The absorption system 822 comprises an absorption unit823, a regenerator 824 and a scrubber 825. The absorption unit 823 canemploy an aqueous solution of various akylamines (also “amines” herein)to scrub CO₂ and H₂S from the stream 820. Examples of amines include,without limitation, diethanolamine, monoethanolamine,methyldiethanolamine and diisopropanolamine. The resultant “rich” amineis then routed into the regenerator 824 (e.g., a stripper with areboiler) to produce regenerated or “lean” amine that is recycled forreuse in the absorption unit 823. The separated CO₂ can be purged 826 orrecycled 827 (e.g., to a methanation system).

The absorption unit 823 generates an effluent stream that can have a lowCO₂ content, which is directed to the scrubber 825. The scrubber 825removes additional CO₂ from the stream, using, for example, a sodiumhydroxide stream that is directed through the scrubber 825 in a counterflow configuration. The stream 828 is then directed from the scrubber825 to a separator 829, which removes water from the stream 828. Theremoved water is directed along stream 819 and the C₂₊ compounds andnon-C₂₊ impurities are directed to dryers 830, and subsequently directedalong stream 831. The OCM effluent stream 828 may be cooled in a heatexchanger upon heat transfer to a C₁ recycle stream, for example.

The system of FIG. 8B employs various heat exchangers. A C₁/N₂ stream isdirected along stream 832 to a heat exchanger and removed along streams833 and 834. Process stream 835, which can comprise methane, is directedto another heat exchanger, and a portion of process stream 835 is thendirected along stream 834 and a remainder is directed along stream 836.A C₁ purge from, for example, a PSA unit, may be directed along stream837 to stream 834.

In FIGS. 8A-8B, in some examples, the separators 808 and 818 can beliquid/liquid separators or gas/liquid separators. For example, theseparator 808 or 818 can be a gas/liquid separator.

One or more ethylene recovery sections (including, for example,separations units and cryogenic units) can comprise a series offractionation towers to separate and recover products. The cooling tocondense each of the column overhead vapors can be provided by multipleways. The lowest temperature required is to condense demethanizeroverhead vapors. In some cases, the demethanizer overhead vapor isexpanded and the chill is utilized to cool the incoming feed streams.

A recycle split vapor (RSV) process can be employed. An RSV process cancomprise a full RSV (modified for the OCM plant) with a propylenerefrigerant, or a full three-refrigerant system typical of an ethyleneplant (methane refrigerant, ethylene refrigerant and propylenerefrigerant, or use a mixed refrigerant composed of two or more of theserefrigerants). In some cases, a combination of these two options (i.e.RSV or modified RSV combined with utilization of one or more of thethree typical refrigeration systems) can be used to provide for therefrigeration duty to the OCM system separation section.

In natural gas processing plants or NGLs fractionation unit, methane canbe separated from ethane and higher carbon-content hydrocarbons(conventionally called natural gas liquids or NGLs) to produce amethane-rich stream that can meet the specifications of pipelines andsales gas. Such separation can be performed using cryogenic separation,such as with the aid of one or more cryogenic units, and/or byimplementing one of the gas processing technologies (e.g., RSV) formaximum or optimum recovery of the NGLs.

The raw natural gas fed to gas processing plants can have a molarcomposition of 70% to 90% methane and 4% to 20% NGLs, the balance beinginert gas(es) (e.g., CO₂ and N₂). The ratio of methane to ethane can bein the range of 5-25. Given the relatively large amount of methanepresent in the stream fed to cryogenic sections of gas processingplants, at least some or substantially all of the cooling duty requiredfor the separation is provided by a variety of compression and expansionsteps performed on the feed stream and the methane product stream. Noneor a limited portion of the cooling duty can be supplied by externalrefrigeration units.

There are various approaches for separating higher carbon alkanes (e.g.,ethane) from natural gas, such as recycle split vapor (RSV) or any othergas processing technologies and/or gas sub-cooled process (GSP)processes, which may maximize the recovery of ethane (e.g., >99%, 98%,97%, 96% or 95% recovery) while providing most or all of the cryogeniccooling duty via internal compression and expansion of portion of thenatural gas itself (e.g., at least about 10%, 15%, 20%, 25%, 30%, 35%,40%, or 50%). However, the application of such approach in separatingalkenes (e.g., ethylene) from an OCM product stream comprising methaneis novel and may result in a limited recovery in some cases when inertgas in present (e.g., provide less than 95% recovery) of the alkeneproduct, due at least in part to i) the different vapor pressure ofalkenes and alkanes, and/or ii) the presence of significant amounts ofH₂ in the OCM product stream, which can change the boiling curve and,particularly, the Joule-Thomson coefficient of the methane stream thatneeds to be compressed and expanded to provide the cooling duty.Hydrogen can display a negative or substantially low Joule-Thomsoncoefficient, which can cause a temperature increase or a substantiallylow temperature decrease in temperature when a hydrogen-reach stream isexpanded.

In some embodiments, the design of a cryogenic separation system of anOCM-based plant can feature a different combination ofcompression/expansion steps for internal refrigeration and, in somecases, external refrigeration. The present disclosure provides aseparation system comprising one or more cryogenic separation units andone or more demethanizer units. Such a system can maximize alkenerecovery (e.g., provide greater than 95% recovery) from a streamcomprising a mixture of alkanes, alkenes, and other gases (e.g., H₂),such as in an OCM product stream.

In such separation system, the cooling duty can be supplied by acombination of expansion of the OCM effluent (feed stream to thecryogenic section) when the OCM effluent pressure is higher than ademethanizer column; expansion of at least a portion or all of thedemethanizer overhead methane-rich stream; compression and expansion ofa portion of the demethanizer overhead methane-rich stream; and/orexternal propane, propylene or ethylene refrigeration units.

FIGS. 9-12 show various separation systems that can be employed withvarious systems and methods of the present disclosure, including smallscale and world scale systems. FIG. 9 shows a separation system 900comprising a first heat exchanger 901, a second heat exchanger 902, ademethanizer 903, and a third heat exchanger 904. The direction of fluidflow is shown in the figure. The demethanizer 903 can be a distillationunit or multiple distillation units (e.g., in series). In such a case,the demethanizer can include a reboiler and a condenser, each of whichcan be a heat exchanger. An OCM effluent stream 905 is directed to thefirst heat exchanger 901 at a pressure from about 10 to 100 bar(absolute), or 20 to 40 bar. The OCM effluent stream 905 can includemethane and C₂₊ compounds, and may be provided in an OCM product streamfrom an OCM reactor (not shown). The OCM effluent stream 905 is thendirected from the first heat exchanger 901 to the second heat exchanger902. In the first heat exchanger 901 and the second heat exchanger 902,the OCM effluent stream 905 is cooled upon heat transfer to ademethanizer overhead stream 906, a demethanizer reboiler stream 907, ademethanizer bottom product stream 908, and a refrigeration stream 909having a heat exchange fluid comprising propane or an equivalent coolingmedium, such as, but not limited to, propylene or a mixture of propaneand propylene.

The cooled OCM effluent 905 can be directed to the demethanizer 903,where light components, such as CH₄, H₂ and CO, are separated fromheavier components, such as ethane, ethylene, propane, propylene and anyother less volatile component present in the OCM effluent stream 905.The light components are directed out of the demethanizer along theoverhead stream 906. The heavier components are directed out of thedemethanizer along the bottom product stream 908. The demethanizer canbe designed such that at least about 60%, 70%, 80%, 90%, or 95% of theethylene in the OCM effluent stream 905 is directed to the bottomproduct stream 908.

The demethanizer overhead stream 906 can contain at least 60%, 65%, 70%,75%, or 80% methane. The overhead stream 906 can be expanded (e.g., in aturbo-expander or similar machine or flashed over a valve or similardevice) to decrease the temperature of the overhead stream 906 prior todirecting the overhead stream 906 to the second heat exchanger 902 andsubsequently the first heat exchanger 901. The overhead stream 906 canbe cooled in the third heat exchanger 904, which can be cooled using areflux stream and a hydrocarbon-containing cooling fluid, such as, forexample, ethylene.

The overhead stream 906, which can include methane, can be recycled toan OCM reactor and/or directed for other uses, such as a natural gaspipeline. In some examples, the bottom product stream, which can containC₂₊ compounds (e.g., ethylene), can be directed to an ETL system.

FIG. 10 shows another separation system 1000 that may be employed foruse with systems and methods of the present disclosure. The direction offluid flow is shown in the figure. The system 1000 comprises a firstheat exchanger 1001, demethanizer 1002 and a second heat exchanger 1003.The demethanizer 1002 can be a distillation unit or multipledistillation units (e.g., in series). An OCM effluent stream 1004 isdirected into the first heat exchanger 1001. The OCM effluent stream1004 can include methane and C₂₊ compounds, and may be provided in anOCM product stream from an OCM reactor (not shown). The OCM effluentstream 1004 can be provided at a pressure from about 10 bar (absolute)to 100 bar, or 40 bar to 70 bar. The OCM effluent stream 1004 can becooled upon heat transfer to a demethanizer overhead streams 1005 and1006 from the second heat exchanger 1003, a demethanizer reboiler stream1007, and a refrigeration stream having a cooling fluid comprising, forexample, propane or an equivalent cooling medium, such as, but notlimited to, propylene or a mixture of propane and propylene. In somecases, the demethanizer overhead streams 1005 and 1006 are combined intoan output stream 1012 before or after passing through the first heatexchanger 1001.

Subsequent to cooling in the first heat exchanger 1001, the OCM effluentstream 1004 can be expanded in a turbo-expander or similar device orflashed over a valve or similar device to a pressure of at least about 5bar, 6 bar, 7 bar, 8 bar, 9 bar, or 10 bar. The cooled OCM effluentstream 1004 can then be directed to the demethanizer 1002, where lightcomponents (e.g., CH₄, H₂ and CO) are separated from heavier components(e.g., ethane, ethylene, propane, propylene and any other less volatilecomponent present in the OCM effluent stream 1004). The light componentsare directed to an overhead stream 1009 while the heavier components(e.g., C₂₊) are directed along a bottoms stream 1010. A portion of theoverhead stream 1009 is directed to second heat exchanger 1003 andsubsequently to the first heat exchanger 1001 along stream 1006. Aremainder of the overhead stream 1009 is pressurized (i.e., pressure isincreased) in a compressor and directed to the second heat exchanger1003. The remainder of the overhead stream 1009 is then directed to aphase separation unit 1011 (e.g., distillation unit or vapor-liquidseparator). Liquids from the phase separation unit 1011 are directed tothe second heat exchanger 1003 and subsequently returned to thedemethanizer 1002. Vapors from the phase separation unit 1011 areexpanded (e.g., in a turbo-expander or similar device) and directed tothe second heat exchanger 1003, and thereafter to the first heatexchanger along stream 1005. The demethanizer 1002 can be designed suchthat at least about 60%, 70%, 80%, 90%, or 95% of the ethylene in theOCM effluent stream 1004 is directed to the bottom product stream 1010.

FIG. 11 shows another separation system 1100 that may be employed foruse with systems and methods of the present disclosure. The direction offluid flow is shown in the figure. The system 1100 comprises a firstheat exchanger 1101, a demethanizer 1102, a second heat exchanger 1103and a third heat exchanger 1104. The system 1100 may not require anyexternal refrigeration. The demethanizer 1102 can be a distillation unitor multiple distillation units (e.g., in series). An OCM effluent stream1105 is directed to the first heat exchanger 1101 at a pressure fromabout 10 bar (absolute) to 100 bar, or 40 bar to 70 bar. In the firstheat exchanger 1101, the OCM effluent stream 1105 can be cooled uponheat transfer to demethanizer overhead streams 1106 and 1107, ademethanizer reboiler stream 1108 and a demethanizer bottom productstream 1109. In some cases, the demethanizer overhead streams 1106 and1107 are combined into a common stream 1115 before or after they arepassed through the first heat exchanger 1101. The OCM effluent stream1105 is then expanded to a pressure of at least about 5 bar, 6 bar, 7bar, 8 bar, 9 bar, 10 bar, or 15 bar, such as, for example, in aturbo-expander or similar machine or flashed over a valve or similardevice. The cooled OCM effluent stream 1105 is then directed to thedemethanizer 1102, where light components (e.g., CH₄, H₂ and CO) areseparated from heavier components (e.g., ethane, ethylene, propane,propylene and any other less volatile component present in the OCMeffluent stream 1105). The light components are directed to an overheadstream 1110 while the heavier components are directed along the bottomproduct stream 1109. The demethanizer 1102 can be designed such that atleast about 60%, 70%, 80%, 90%, or 95% of the ethylene in the OCMeffluent stream 1105 is directed to the bottom product stream 1109.

The demethanizer overhead stream 1110, which can contain at least 50%,60%, or 70% methane, can be divided into two streams. A first stream1111 is compressed in compressor 1112 and cooled in the second heatexchanger 1103 and phase separated in a phase separation unit 1113(e.g., vapor-liquid separator or distillation column). Vapors from thephase separation unit 1113 are expanded (e.g., in a turbo-expander orsimilar device) to provide part of the cooling duty required in heatexchangers 1101, 1103 and 1104. Liquids from the phase separation unit1113 are sub-cooled in the third heat exchanger 1104 and recycled to thedemethanizer 1102. A second stream 1114 from the overhead stream 1110can be expanded (e.g., in a turbo-expander or similar device) todecrease its temperature and provide additional cooling to the heatexchangers 1101, 1103 and 1104.

FIG. 12 shows another separation system 1200 that may be employed foruse with systems and methods of the present disclosure. The direction offluid flow is shown in the figure. The system 1200 comprises a firstheat exchanger 1201, a demethanizer 1202, and a second heat exchanger1203. An OCM effluent stream 1204 is directed to the first heatexchanger 1201 at a pressure from about 2 bar (absolute) to 100 bar, or3 bar to 10 bar. The first heat exchanger 1201 can interface with apropane refrigeration unit 1215 and/or an ethylene refrigeration unit1216. In the first heat exchanger 1201, the OCM effluent stream 1204 canbe cooled upon heat transfer to demethanizer overhead streams 1205 and1206, a demethanizer reboiler stream, a demethanizer pump-around stream,and various levels of external refrigeration, such as using coolingfluids comprising ethylene and propylene. In some cases, thedemethanizer overhead streams 1205 and 1206 are combined into a singlestream 1214 before or after they are cooled. The cooled OCM effluentstream 1204 is then directed to the demethanizer 1202, where lightcomponents (e.g., CH₄, H₂ and CO) are separated from heavier components(e.g., ethane, ethylene, propane, propylene and any other less volatilecomponent present in the OCM effluent stream 1204). The light componentsare directed to an overhead stream 1207 and the heavier components aredirected along a bottom product stream 1208. The demethanizer 1202 canbe designed such that at least about 60%, 70%, 80%, 90%, or 95% of theethylene in the OCM effluent stream 1204 is directed to the bottomproduct stream 1208.

The demethanizer overhead stream, which can contain at least about 50%,60%, 70%, or 80% methane, can be divided into two streams. A firststream 1213 can be compressed in a compressor 1209, cooled in the secondheat exchanger 1203 and phase-separated in a phase separation unit 1210(e.g., distillation column or vapor-liquid separator). Vapors from thephase separation unit 1210 can be expanded (e.g., in a turbo-expander orsimilar device) to provide part of the cooling duty required for theheat exchanger 1201 and 1203. Liquids from the phase separation unit1210 can be sub-cooled and flashed (e.g., over a valve or similardevice), and the resulting two-phase stream is separated in anadditional phase separation unit 1211. Liquids from the additional phaseseparation unit 1211 are recycled to the demethanizer 1202 and vaporsfrom the additional phase separation unit are mixed with expanded vaporsfrom the phase separation unit 1210 prior to being directed to thesecond heat exchanger 1203.

A second stream 1212 from the overhead stream 1207 can be expanded(e.g., in a turbo-expander or similar device) to decrease itstemperature and provide additional cooling for the heat exchanger 1201and 1203. Any additional cooling that may be required for the secondheat exchanger 1203 can be provided by an external refrigeration system,which may employ a cooling fluid comprising ethylene or an equivalentcooling medium.

In some cases, recycle split vapor (RSV) separation can be performed incombination with demethanization. In such a case, at least a portion ofthe overhead stream from a demethanizer unit (or column) may be splitinto at least two streams (see, e.g., FIGS. 10-12). At least one of theat least two streams may be pressurized, such as in a compressor, anddirected to a heat exchanger.

In some instances, the methane undergoes an OCM and/or ETL process toproduce liquid fuel or aromatic compounds (e.g., higher hydrocarbonliquids) and contains molecules that have gone through methanation. Insome embodiments, the compounds have been through a recycle split vapor(RSV) separation process. In some cases, alkanes (e.g., ethane, propane,butane) are cracked in a post-bed cracker.

It will be appreciated that systems and methods described herein areprovided as examples and that various alternatives may be employed. Itwill be further appreciated that components of systems described hereinare interchangeable. For instance, components for use in small scaleproduction may be employed for use in world scale production, and viceversa.

Air Separation Units (ASU) and Power Production

An OCM reaction can convert a natural gas into a stream containingethane, ethylene and other short olefins and alkanes, such as propeneand propane. Unlike conventional (i.e., non-OCM) cracking-basedproduction technologies for olefin production which may utilize energyto sustain the cracking reaction, the OCM process can generate powerfrom the exothermic OCM reaction itself. Provided herein are systems andmethods that can utilize the OCM reaction heat for steam generation,which in turn can be exploited for power generation.

In an OCM process, methane can react with an oxidizing agent such asoxygen over an OCM catalyst to generate ethylene. A wide set ofcompetitive reactions can occur simultaneously over the OCM catalyst,including combustion of both methane and partial oxidations. Natural gascan be the source of methane, and can be combined with one or morerecycle streams coming from downstream separation units (e.g., which cancontain methane and ethane). Air, enriched air or pure oxygen can beused to supply the oxygen required for the reaction. All these reactionsare exothermic and the relevant reaction heat can be recovered in orderto cool the reactor effluent and feed the effluent to a downstreamcompressor, which can then send the effluent stream to downstreamseparation and recovery units.

Several process configurations can be adopted to enable the efficientrecovery of the reaction heat. In some cases, the process utilizes theOCM reaction heat to i) supply the heat for the endothermic crackingreactions that convert the additional ethane feed to ethylene; and ii)generate steam to drive a downstream compressor. This process canachieve energy neutrality (no need for energy import or export toconduct the overall process), however it can require a relatively largenumber of unit operations which can lead to operational complexity,large capital costs and high pressure drops between the reactor outletand the compressor suction. When the OCM process is combined with powergeneration, the integrated OCM-power process can be a simpler and moreefficient process when compared to an individual OCM process and aseparate power production unit producing the same amounts of ethyleneand power.

This flexibility and synergy between olefin and power production can beexploited as a design feature and/or an operating feature. That is, theprocess configuration of an integrated OCM-power system can be designedin order to maximize ethylene production, or power production, or forany intermediate level of production of the two products. In the case ofmaximum ethylene production, the flow of the ethane stream injected intothe OCM reactor can be maximized to conduct cracking reactions to themaximum allowable extent. If the OCM reactor is adiabatic, the maximumextent of cracking corresponds to designing the system to crack anamount of ethane that results in a decrease in temperature to theminimum viable temperature for cracking. In the case of maximum powerproduction, the system can be designed for minimum ethane injection,which can be limited by the highest possible temperature at the outletof the OCM reactor and, accordingly, the maximum amount of steamgeneration. The combined OCM-power system can be designed to operate atany level of power and olefin production in between these twoconstraints.

The same flexibility and synergy between ethylene and power productioncan be achieved at an operating level. For example, the combinedOCM-power process can be designed to handle both the maximum olefin andthe maximum power cases. In such cases, the plant operator has theability to change the amount of ethylene and power production duringoperations by deciding at any given time the amount of ethane to beinjected into the OCM reactor. This operating feature can beparticularly advantageous for optimizing the financial performance ofthe plant once it is built because it can allow variation of thecomposition of the product portfolio at any given time based on the realtime prices of the respective products.

An aspect of the present disclosure provides an oxidative coupling ofmethane (OCM) system for production of olefins and power. The system caninclude an OCM subsystem that takes as input a feed stream comprisingmethane (CH₄) and a feed stream comprising an oxidizing agent such asoxygen, and generates a product stream comprising C₂₊ compounds and heatfrom the methane and the oxidizing agent. The system can further includea power subsystem fluidically or thermally coupled to the OCM subsystemthat converts the heat into electrical power.

The OCM subsystem can have at least one OCM reactor and at least onepost-bed cracking unit within the OCM reactor or downstream of the OCMreactor. The post-bed cracking unit can be configured to convert atleast a portion of alkanes in the product stream to alkenes. In somecases, the power subsystem has one or more turbines and can be a gasturbine combined cycle (GTCC). In some embodiments, the system furthercomprises a heat recovery steam generator (e.g., HRSG) for generatingsteam from the heat and the steam can be converted to electrical powerin the power subsystem. In some instances, the power subsystem comprisesa gas turbine and un-reacted methane from the OCM subsystem is convertedto electrical power using the gas turbine.

Another aspect of the present disclosure provides a method for producingat least one C₂₊ alkene and power. The method can include directingmethane and an oxidizing agent into a reactor comprising a catalystunit, where the catalyst unit comprises an oxidative coupling of methane(OCM) catalyst that facilitates an OCM reaction that produces C₂₊alkene. The method can include reacting the methane and oxidizing agentwith the aid of the OCM catalyst to generate at least one OCM productcomprising at least one C₂₊ compound and heat. Electrical power can begenerated from the heat.

In some cases, the heat is converted to steam and the steam is convertedto power in a steam turbine. In some cases, un-reacted methane from thereactor is converted to electrical power in a gas turbine. In someinstances, the reactor includes a cracking unit downstream of thecatalyst unit, where the cracking unit generates C₂₊ alkene from C₂₊alkane. The method can further include providing at least onehydrocarbon-containing stream that is directed through the crackingunit, which hydrocarbon-containing stream has at least one C₂₊ alkane.At least one C₂₊ alkane can be cracked to provide the at least one C₂₊alkene in a product stream that is directed out of the reactor. In someembodiments, the hydrocarbon-containing stream comprises at least oneOCM product. The C₂₊ alkene produced from the hydrocarbon-containingstream in the cracking unit can be in addition to the C₂₊ alkeneproduced from the methane and the oxidizing agent in the reactor. Insome embodiments, the amount of steam produced is varied or the amountof at least one hydrocarbon-containing stream that is directed throughthe cracking unit is varied to alter the amount of electrical powerproduced and the amount of C₂₊ alkene produced.

FIG. 13 shows an example of a HRSG system 1300 that may be employed foruse as the HRSG 507. The HRSG system 1300 comprises a gas turbine 1301,HRSG 1302, power generation unit 1303 and an air separation unit (ASU)1304. The system 1300 comprises streams 1305, 1306, 1309 and 1310.

During use, the HRSG 1302 can transfer heat to a methane-containingstream (e.g., methane-containing stream 505). Purge gas from an OCMprocess can be burned to compress air as feed to ASU unit 1304.Additional high pressure steam may be provided along stream 1306. Powergenerated by the power generation unit 1303 can be directed to an OCMsystem 1307, an energy storage unit or power distribution system 1308,and/or the ASU 1304. The air separation unit accepts compressed air fromthe gas turbine 1301 and separates the compressed air to O₂ that isdirected along stream 1309 and N₂, which can be purged. The HRSG system1300 further comprises a purge stream 1305 that is directed into the gasturbine, and a flue gas stream 1310 that is directed out of the HRSG1302.

FIG. 14 shows an example of an OCM process for producing ethylene andpower. Natural gas 1402 and in some cases, additional ethane 1404, canbe cleaned of sulfur-containing compounds in a de-sulfurization unit1406 and fed into a process gas compressor 1408. Carbon dioxide (CO₂)1410 can be removed in a process gas cleanup module 1412 and fed to themethanation reactor 1426 (connection not shown). The gas cleaned of CO₂can be fed into a separations module 1414 where one or more productfractions 1416 can be isolated (e.g., C₂, C₃, C₄₊ compounds).

Alkanes such as ethane can be recycled 1418 from the separations moduleto the OCM reactor 1420, where they can be injected into the post-bedcracking region of the reactor to generate olefins from the alkanes. Thealkane recycle stream 1418 can be heated in a heat exchanger or a heatrecovery steam generator (HRSG) 1422 (for simplicity, connection to HRSGnot shown). Carbon monoxide 1424 from the separations module 1414 andcarbon dioxide from module 1412 (connection not shown) can be fed into amethanation reactor 1426 along with hydrogen 1424 for conversion tomethane. The methane recycle 1428 can be heated in the HRSG 1422 andreturned to the OCM reactor 1420.

The HRSG can provide high-pressure steam 1430 to a steam turbine 1432 toproduce power 1434. The steam and energy to heat the steam can besourced from any suitable part of the process including from the OCMreactor 1436. Additional sources of steam and/or heat can include fromcombustion of fuel gas 1438 provided from the separations module, fromthe exhaust 1440 from a gas turbine 1445, and/or from cooling theeffluent from the OCM reactor 1420 (not shown). Additional fuel gas 1450can be provided to the gas turbine 1445. The gas turbine can produceelectrical power 1455 and can drive a compressor (e.g., on the sameshaft with the power generator) to supply compressed air 1460 for an airseparation unit (ASU) 1465 or a vacuum pressure swing adsorption (VPSA)unit to supply oxygen to the OCM reactor 1420.

The combined OCM-power process shown in FIG. 14 can have numerousadvantages over processes without power integration (e.g., FIGS. 26-31).For example, the total number of unit operations can be lower due to theheat recovery section of the combined cycle GTCC (that recovers the heatfrom the gas turbine exhaust) being utilized for OCM-related services,thus making a feed-product exchanger and a steam superheater redundant.The lower number of unit operations can lead to lower capital cost andoperational simplicity. The pressure drop from the OCM reactor outlet tothe compressor suction can be reduced by up to 2 bar due to theelimination of two large heat exchangers when integrating OCM with powerproduction. The reduced pressure drop can leads to an increased processefficiency (due to the lower power consumption in compressors) and alower capital cost (due to the smaller size of the compressors).

Oxidizing Agents

An OCM process requires the presence of an oxidizing agent. Theoxidizing agent can be oxygen supplied from air fed to the reactor. Insome cases the oxidizing agent can be pure oxygen, supplied by pipelineor recovered from air. In some cases oxygen can be separated from air bycryogenic distillation, as in an Air Separation Unit. In some cases,various membrane separation technologies can be applied to generate anoxygen rich stream. In certain cases, the oxygen stream can be producedby a pressure swing adsorption (PSA) unit or a vacuum pressure swingadsorption (VPSA) unit. In certain cases, while using air as theoxidizing agent, a nitrogen recovery unit (NRU) can be used to reducethe nitrogen content in the OCM reactor system. See, e.g., U.S. patentapplication Ser. No. 13/739,954 and U.S. patent application Ser. No.13/936,870, which are entirely incorporated herein by reference.

Ethane Skimming

Systems and methods of the present disclosure can be used to convertboth methane and ethane to ethylene, in some cases along with someco-products and by-products. Ethane can be fed directly into a post-bedcracker (PBC), which can be a portion of an OCM reactor downstream ofthe OCM catalyst, where the heat generated in the OCM reaction can beused to crack the ethane to ethylene. As an alternative, the PBC can bea unit that is separate from the OCM reactor and in some cases inthermal communication with the OCM reactor. The ethane feed stream tothe OCM reactor can include (a) ethane recycled to the OCM reactor froman OCM reactor effluent stream, which can be separated in at least onedownstream separation module and recycled to the OCM reactor, (b) ethanepresent in other feed streams (e.g., natural gas), which can beseparated in at least one separation module and recycled to the OCMreactor, and (c) any additional (i.e., fresh) ethane feed.

The maximum amount of ethane that can be converted in the PBC can belimited by the flow rate of material exiting the OCM catalyst and/or itstemperature. It can be advantageous to utilize a high proportion of themaximum amount of PBC. In some cases, the amount of ethane converted toethylene is about 50%, about 60%, about 70%, about 80%, about 85%, about90%, about 95%, or about 99% of the maximum amount of ethane that can beconverted to ethylene in the PBC. In some instances, the amount ofethane converted to ethylene is at least about 50%, at least about 60%,at least about 70%, at least about 80%, at least about 85%, at leastabout 90%, at least about 95%, or at least about 99% of the maximumamount of ethane that can be converted to ethylene in the PBC.

Achieving a high proportion (e.g., greater than or equal to about 60%,70%, or 80%) of the maximum PBC capacity can be accomplished by addingnatural gas to the system, which can have a concentration of ethane thatdepends on many factors, including the geography and type and age of thenatural gas well. The treatment and separation modules of the OCMprocess described herein can be used to purify the OCM effluent, but canbe used to treat (e.g., remove water and CO₂) and purify the natural gasthat is added to the system along with the OCM effluent, such as, e.g.,by separating C₂₊ compounds from methane and separating ethane fromethylene. In some cases, ethane contained in the natural gas feed can berecycled to the OCM reactor (e.g., PBC region) as pure ethane and thesystem may not be sensitive to the purity and composition of the naturalgas, making raw natural gas a suitable input to the system.

The maximal PBC capacity can depend on the ratio between methane andethane in the input to the OCM reactor, including in some instances thePBC portion. In some cases, the PBC capacity is saturated when the molarratio of methane to ethane is about 1, about 2, about 3, about 4, about5, about 6, about 7, about 8, about 9, about 10, about 11, about 12,about 13, about 14, or about 15. In some cases, the PBC capacity issaturated when the molar ratio of methane to ethane is at least about 1,at least about 2, at least about 3, at least about 4, at least about 5,at least about 6, at least about 7, at least about 8, at least about 9,at least about 10, at least about 11, at least about 12, at least about13, at least about 14, or at least about 15. In some cases, the PBCcapacity is saturated when the molar ratio of methane to ethane is atmost about 5, at most about 6, at most about 7, at most about 8, at mostabout 9, at most about 10, at most about 11, at most about 12, at mostabout 13, at most about 14 or at most about 15. In some cases, the PBCcapacity is saturated when the molar ratio of methane to ethane isbetween about 7 and 10 parts methane to one part ethane.

Natural gas (raw gas or sales gas) can have a concentration of ethane ofless than about 30 mol %, 25 mol %, 20 mol %, 15 mol %, 10 mol %, 9 mol%, 8 mol %, 7 mol %, 6 mol %, 5 mol %, 4 mol %, 3 mol %, 2 mol % or 1mol %. In some cases, natural gas has a methane to ethane ratio greaterthan about 1:1, 2:1, 3:1, 4:1, 5:1, 6:1, 7:1, 8:1, 9:1, 10:1, 11:1,12:1, 13:1, 14:1, 15:1, 16:1, 17:1, 18:1, 19:1, 20:1 or 40:1. The ethaneskimmer implementation of OCM described herein can be used to injectmore natural gas feed into the system than what may be required toproduce the desired or predetermined amount of ethylene. The excessmethane can be drawn from a stream downstream of the methanation unitand sold as sales gas (which may lack an appreciable amount of ethanebut can still meet pipeline specifications and/or can be directed to apower plant for power production). The ethane in the additional naturalgas feed can be used to saturate the PBC capacity. Any excess ethane canbe drawn from the C₂ splitter and exported as pure ethane. The ethaneskimmer implementation described herein can result in additional productstreams from the OCM system (namely sales gas and natural gas liquids).In such a case, the OCM process can be used to achieve both ethyleneproduction and natural gas processing.

The ethane skimmer implementation can be readily understood by referenceto FIG. 15 (showing additional ethane feed to saturate PBC) and FIG. 16(showing the ethane skimmer implementation). In FIG. 15, at least someor most (e.g., >70%, >80%, >85%, >90%, >95%, or >99%) of the methane inthe natural gas (NG) feed 1500 ends up in the methane recycle 1505, atleast some or most (e.g., >70%, >80%, >85%, >90%, >95%, or >99%) of theethane in the NG feed ends up in the ethane recycle stream 1510, atleast some or most (e.g., >70%, >80%, >85%, >90%, >95%, or >99%) propanein the NG feed ends up in the C₃ mixed products stream (e.g., RefineryGrade Propylene (RPG)) 1515, at least some or most(e.g., >70%, >80%, >85%, >90%, >95%, or >99%) of the C₄₊ in the NG feedends up in the C₄ mixed stream 1520, and ethane is added 1525 up to thepoint where the PBC cracking capacity 1530 is saturated or nearlysaturated (e.g., >70%, >80%, >85%, >90%, >95%, or >99%). In contrast, inthe ethane skimmer implementation (FIG. 16), some of the methane (anyproportion) can end up in a sales gas stream 1600 and if there is excessethane, it can end up in an ethane product stream 1605. The ethaneskimmer implementation does not require a separate (i.e., fresh) ethanestream to saturate or nearly saturate the PBC capacity of the system.

Gas Processing Plants

An OCM process for generating olefins (e.g., ethylene) can be astandalone process, or it can be integrated in other processes, such asnon-OCM processes (e.g., NGL process). FIG. 17 shows a system 1700comprising an existing gas plant 1701 that has been retrofitted with anOCM system 1702 (or with an OCM-ETL system for the production of otherolefins (e.g., propylene)). A raw natural gas (NG) feed 1703 is directedinto the existing gas plant 1701, which comprises a treatment unit 1704,NGL extraction unit 1705, compression unit 1706 and fractionation unit1707. The NGL extraction unit 1705 can be a gas processing unit that canuse a gas processing recovery technology such as a recycle split vapor(RSV) technology or other technologies. The NGL extraction unit 1705 canbe a demethanizer unit, optionally a demethanizer unit incorporated witha recycle split vapor (RSV) retrofit or standalone unit. The treatmentunit 1704 can remove water, H₂S and CO₂ from the NG feed 1703 and directnatural gas to the NGL extraction or processing unit 1705. The NGLextraction unit 1705 can remove NGLs (e.g., ethane, propane, butane,etc.) from methane and direct methane (with some traces of NGLs andinert gas) to the compression unit 1706 along fluid stream 1708. NGLs orC₂₊ components can be directed to fractionation unit 1707. At least aportion or almost all of the methane (e.g., 10%, 20%, 30%, 40%, 50%,60%, 70%, 80%, 90%, or 99%) from the fluid stream 1708 is directed alongstream 1709 to an OCM reactor 1710 of the OCM system 1702. Thisintegration of an OCM system (in some other cases OCM-ETL system) withan existing natural gas processing or NGLs extraction plant can improvethe recovery of olefin/is production by implementing one of the gasprocessing technologies (e.g., RSV). This integration is suitable for asmall scale and world scale olefin production (e.g., ethyleneproduction).

With continued reference to FIG. 17, the compression unit 1706compresses methane in the fluid stream 1708 and directs compressedmethane to a methanation system 1711, which converts any CO, CO₂ and H₂in the fluid stream 1708 to methane, which is then directed to naturalgas pipeline 1712 for distribution to end users. In some cases, themethanation outlet stream can be treated to remove water (not shown).The dryer system can consist one or more of the following. A bed ormultiple desiccant (molecular sieve) beds, separator vessels to condenseand separate the water.

The NGLs extraction unit 1705 can extract C₂₊ compounds from the NG feed1703. NGLs or C₂₊ compounds from the NGL extraction unit 1705 aredirected to the fractionation unit 1707, which can be a distillationcolumn. The fractionation unit 1707 splits the C²⁻ compounds intostreams comprising various C₂₊ compounds, such as a C₂ stream along withC₃, C₄ and C₅ streams. The C₂ stream can be directed to a C₂ splitter1713 (e.g., distillation column), which separates ethane from ethylene.Ethane is then directed along stream 1714 to a post-bed cracking (PBC)unit 1715 of the OCM system 1702. In some cases, C₃ and/or C₄ compoundscan be taken from the C₂ splitter 1713 and fed into a downstream regionof a post-bed cracking (PBC) reactor for olefin production. In somesituations, C₄ and/or C₅ streams can be directed to a C₄ or C₅ splitter(e.g., a distillation column), which, for example, separate iso-butane(iC₄) from normal butane (nC₄) and/or separate iso-pentane (iC₅) fromnormal pentane (nC₅). In some situations, other alkanes, such as propaneand butane, can be directed to the PBC unit 1715.

In the OCM system 1702, methane from the stream 1709 and oxygen alongstream 1716 are directed to the OCM reactor 1719. The OCM reactor 1710generates an OCM product (or effluent) stream comprising C₂₊ compoundsin an OCM process, as discussed elsewhere herein. C₂₊ alkanes (e.g.,ethane) in the product stream, as well as C₂ alkanes in the stream 1714,may be cracked to C₂₊ alkenes (e.g., ethylene) in the PBC unit 1715downstream of the OCM reactor 1710. The product stream is then directedto a condenser 1717, which removes water from the product stream. Theproduct stream is then directed to a compression unit 1718 andsubsequently another compression unit 1719. Methane from the compressionunit 1719 is directed to the NG feed 1703 along stream 1720.

The OCM system 1702 can include one or more OCM reactor 1710. Forexample, the OCM reactor 1710 can be an OCM reactor train comprisingmultiple OCM reactors. The OCM system 1702 can include one or more PBCreactors 1715.

The compression units 1718 and 1719 can each be a multistage gascompression unit. Each stage of such multistage gas compression unit canbe followed by cooling and liquid hydrocarbon and water removal.

Ethylene Plants

In an aspect, the present disclosure provides a method for producing C₂₊compounds by performing an oxidative coupling of methane (OCM) reactionto produce an OCM effluent comprising methane (CH₄), hydrogen (H₂),carbon dioxide (CO₂), ethylene (C₂H₄) and C₂₊ compounds. The OCMeffluent can be separated into a first stream comprising C₂₊ compoundsand a second stream comprising CH₄, CO₂, and H₂. The second stream canbe methanated to produce a first OCM reactor feed comprising additionalCH₄ formed from the CO₂ and the H₂ in the second stream. A third streamcan be methanated to produce a second OCM reactor feed comprising CH₄.The third stream can comprise CH₄ and H₂ from demethanizer off-gas froman ethylene cracker. The first and second OCM reactor feeds can then beprovided to the OCM reaction.

In some embodiments, the second stream and the third stream aremethanated in a single methanation reactor. The method can furthercomprise providing the first stream to the separation section of theethylene cracker. The ethylene cracker can be an existing ethylenecracker, which may be present prior to retrofitting with an OCM reactorand additional unit operations. The separation section may be evaluatedfor available capacity to process the additional feed. In some cases,the cracker operation can be modified to operate at a lower severity,hence making some additional capacity available in the existingseparation section, especially C₁, C₂ and C₃ area. In some cases, thefirst stream is provided to a gas compressor or a fractionation unit ofthe ethylene cracker. In some embodiments, the third stream is theoverhead stream of a demethanizer of the ethylene cracker. In somecases, separation is performed in a pressure swing adsorption (PSA)unit. In some embodiments, the OCM effluent is compressed prior toseparating in the PSA unit. In some cases, the separation section alsoincludes, but is not limited to, a CO₂ removal system, which typicallyincludes an amine system or a caustic tower and/or dryers to removewater from the OCM effluent.

The method can further comprise feeding oxygen (O₂) to the OCM reaction.In some cases, the OCM effluent further comprises carbon monoxide (CO)and the CO is converted into CH₄ in operation (c). In some instances,the third stream further comprises CO₂ or CO. The OCM reaction canfurther react additional CH₄ from external supply of natural gas. Insome embodiments, the third stream further comprises CH₄.

In another aspect, the present disclosure provides an oxidative couplingof methane (OCM) system for production of C²⁻ compounds. The system cancomprise an OCM subsystem that (i) takes as input a feed streamcomprising methane (CH₄) and a feed stream comprising an oxidizingagent, and (ii) generates a product stream comprising C₂₊ compounds fromthe CH₄ and the oxidizing agent. The system can further comprise aseparation subsystem fluidically coupled to the OCM subsystem thatseparates the product stream into (i) a first stream comprising C²⁻compounds and (ii) a second stream comprising methane (CH₄) hydrogen(H₂) and carbon dioxide (CO₂) and/or carbon monoxide (CO). The systemcan further comprise a methanation subsystem fluidically coupled to thesecond stream and to the OCM subsystem, wherein the methanationsubsystem converts H₂ and CO₂ and/or CO into CH₄. The system can furthercomprise an ethylene cracker subsystem fluidically coupled to themethanation subsystem that provides additional CH₄ and H₂ to themethanation subsystem.

In some embodiments, the methanation subsystem provides CH₄ for the OCMsubsystem. The additional CH₄ and H₂ can be derived from thedemethanizer overhead of the ethylene cracker subsystem. The firststream comprising C₂+ components can be fluidically coupled to theethylene cracker subsystem. The first stream can be fractionated in theethylene cracker subsystem. The separation subsystem can include apressure swing adsorption (PSA) unit.

In some instances, the OCM subsystem is supplied additional CH₄ from anatural gas feed stream. In some cases, the oxidizing agent is O₂ (e.g.,provided by air from an air separation unit or any other type of oxygenconcentration unit).

In some embodiments, the OCM subsystem comprises at least one OCMreactor. In some instances, the OCM subsystem comprises at least onepost-bed cracking unit within the at least one OCM reactor or downstreamof the at least one OCM reactor, which post-bed cracking unit isconfigured to convert at least a portion of alkanes in the productstream to alkenes. In some cases, the reactor is adiabatic. In someinstances, the post-bed cracking unit uses ethane and propane recyclestreams from the existing Ethylene cracker subsystem to achieveconversion to ethylene. In some cases, the recycle streams are routed tothe cracking furnaces to completely crack the recycle streams.

FIG. 18 shows an example of an OCM process integrated with an existingethylene cracker. The OCM reactor 1800 takes in methane and oxygen 1802and produces an OCM effluent 1805 having CO₂, CH₄ and C₂H₄, in somecases amongst other components, such as H₂ and CO. The OCM reaction canbe exothermic and can produce steam 1807. The OCM effluent 1805 can becompressed in a compressor 1810 and fed into a pressure swing adsorption(PSA) unit 1815.

The PSA unit can produce an overhead stream 1820 that can include H₂,CH₄, CO₂ and CO. The overhead stream can be fed into a methanationsubsystem 1822 (e.g., methanation reactor) to provide methane for theOCM reactor 1800. Additional methane can be provided by way of a naturalgas stream 1824.

The process of FIG. 18 further includes an existing ethylene cracker1830 with a demethanizer off gas stream. Demethanizer off gas from theexisting ethylene cracker 1830 subsystem can supply additional CH₄ andH₂ that may be required for methanation. Methane generated in theethylene cracker 1830 can be returned to the OCM reactor 1800 via stream1826.

Heavier components can exit the PSA separately 1825 and include ethane,ethylene and C₃₊ compounds, which can be fractionated using existingseparations capacity in the ethylene cracker 1830. The heavy componentscan be processed in the fractionation towers of the ethylene cracker,optionally first being compressed in the existing process gas compressorof the ethylene cracker. In some cases, the heavy components stream canbe routed to the CO₂ removal unit of the existing ethylene crackersubsystem to meet the CO₂ specification.

In processes, systems, and methods of the present disclosure, aFischer-Tropsch (F-T) reactor can be used to replace a methanationreactor, for example in a methane recycle stream. CO and H₂, such asthat found in a methane recycle stream, can be converted to a variety ofparaffinic linear hydrocarbons, including methane, in an F-T reaction.Higher levels of linear hydrocarbons, such as ethane, can improve OCMprocess efficiency and economics. For example, effluent from an OCMreactor can be directed through a cooling/compression system and otherprocesses before removal of a recycle stream in a de-methanizer. Therecycle stream can comprise CH₄, CO, and H₂, and can be directed into anF-T reactor. The F-T reactor can produce CH₄ and C²⁻ paraffins forrecycling into the OCM reactor. A range of catalysts, including anysuitable F-T catalyst, can be employed. Reactor designs, including thosediscussed in the present disclosure, can be employed. F-T reactoroperation conditions, including temperature and pressure, can beoptimized. This approach can reduce H₂ consumption compared to amethanation reactor.

The combination of a new OCM unit and an existing ethylene cracker isexpected to have certain synergistic benefits. In some cases, prior toretrofit of an ethylene cracker with OCM, the entire overhead from theexisting demethanizer was being used as fuel gas, and can now beavailable as one of the feeds to the methanation unit. In some cases,the demethanizer overhead off-gas comprises up to 95% methane which canbe converted to Ethylene in the OCM reactor, hence increasing the totalethylene capacity. In some cases, the hydrogen content in the existingdemethanizer overhead is substantial, and may be enough to meet thehydrogen requirement of the methanation unit.

In some cases, retrofitting an ethylene cracker with OCM reduces (orallows for reduction of) the severity of cracking in the existingcracker, enabling value addition by increasing the production ofpyrolysis gasoline components in the cracker effluent, as the OCMreactor produces the ethylene needed to achieve the total systemcapacity. The cracker can then be operated on high propylene mode toproduce more propylene and at the same time meeting the ethyleneproduction rate by the new OCM unit. This retrofit can result in greaterflexibility for the ethylene producer with respect to the existingcracker operation.

In some instances, the overall carbon efficiency is increased as themethane and hydrogen from the existing demethanizer off-gases can beutilized to convert the carbon dioxide and carbon monoxide to methane,which is fed to the OCM reactor.

In some instances, ethane and/or propane recycle streams from theexisting cracker can be routed to the OCM unit (e.g., instead of thecracking furnaces). These recycle streams are typically routed to thecracking furnaces where they are “cracked to extinction.” The advantageover routing the recycle streams to OCM over the cracking furnace ishigher selectivity to ethylene in the OCM process.

Purge gas from the OCM-methanation system can (at least partially) meetthe fuel gas requirements of the existing cracker complex. In somecases, the fuel requirements are met by the existing demethanizeroff-gas.

Additional capacity (e.g., for ethylene, propylene or pyrolysis gasolinecomponents) can be gained by integrating an OCM unit and supplyingadditional natural gas feed to the OCM reactor unit which will increaseethylene production, and the existing cracker can be operated at areduced severity and/or increased throughput to produce more olefinand/or pyrolysis gas components. Additional fractionation equipment canbe used to recover ethylene, for example, if the existing separationssection does not have sufficient capacity, or if the existing cracker isoperated at a substantially higher throughput than it was built for.

With regard to the present disclosure allowing for reduced severity ofcracking, a cracking furnace can thermally crack the hydrocarbon feedcomprising of a full range naphtha, light naphtha, ethane, propane orLPG feed to produce ethylene and propylene, along with pyrolysis gasoil, fuel oil and a methane-rich off-gas. The product mix can depend onthe feed composition and the process operating conditions. Importantprocess variables can include steam to hydrocarbon ratio (which can varyfrom 0.3 for ethane and propane feed, and 0.5 for naphtha feed and ashigh as 0.7 for light vacuum gas oil feeds), temperature (which can varyfrom 750-850° C.), and the residence time (which can vary, typically inthe range of 0.1 to 0.5 seconds). The cracking reaction is favored bylow hydrocarbon partial pressure and hence steam can be added to reducethe hydrocarbon partial pressure. Higher steam to hydrocarbon ratio canimprove selectivity at the cost of more energy. Severity is the extentor the depth of cracking, with higher severity achieved by operating thecracking furnace at a higher temperature. High severity operation yieldsmore ethylene, and also results in higher rate of coke formation andhence a reduced time between decoking. As the cracking severity isreduced, the yield of ethylene and lighter components decreases and theyield of propylene and heavier components increases. For liquid feeds,severity is measured as the weight ratio of propylene to ethylene in thecracked gases. For gaseous feeds, severity is measured as percentageconversion (mass) of the key components (e.g., percentage disappearanceof ethane or propane). The cracking furnace can be operated to maximizeethylene or propylene, depending on the economics and demand. Anotherprocess variable in cracker operation is the coil outlet pressure (COP)which is the pressure at the outlet of furnace coils. Low absolutepressure improves selectivity and the pressure is usually kept at about30 psia for gaseous feeds and 25 psia for liquid feeds.

For example, the influence of pyrolysis temperature can be isolated bykeeping the residence time and steam content constant. As the furnaceexit temperature increase, ethylene yield also rises, while yields ofpropylene and pyrolysis gasoline decrease. At very high temperature,residence time can become the controlling factor. Highest ethyleneyields can be achieved by operating at high severity (e.g., about 850°C.), with residence time ranging from 0.2 to 0.4 seconds.

There are numerous ways that the synergies between an OCM unit and anexisting ethylene cracker can be realized. Depending on the desiredproduct cut, the OCM unit can significantly increase the flexibility ofoperation and provide additional capacity gain at a lower incrementalcost. Based on the existing plant operation, the desired productspectrum and natural gas availability, integrating an OCM unit with anexisting ethylene plant (e.g., naphtha cracker or gas cracker) can offerconsiderable benefits including:

In some cases, natural gas is more economical than naphtha forconverting to ethylene and propylene. Integration with OCM can providethe plant the flexibility to operate with a different feedstock atdesired severity. In some cases, the integrating with OCM gives anoperational flexibility, to operate at the desired throughput and feedmix depending on the option that makes best economic sense for theoperator.

Installing more cracking capacity to an existing cracker can require theentire train of process units to be debottlenecked (e.g., quench,gasoline fractionation, compression, refrigeration, and recovery unit).In contrast, gaining capacity by integrating with OCM can result inminimum impact on the existing process unit debottlenecking. Forexample, since the OCM reaction is highly selective to ethylene (e.g.,greater than 50%), there can be a minimum impact on the rest of thesystem (e.g., especially the hot section and C₃₊ handling unit).

The OCM reaction is highly exothermic and the high heat of reaction canbe put to multiple uses. It may be used to crack more ethane (e.g., fromthe ethane and propane recycle streams of the existing cracker) tofurther improve conversion to ethylene. The heat of reaction may also beused to generate steam which can be used to meet process requirements orgenerate power. The OCM unit can be a net exporter of steam and/orpower.

Pyrolysis Process Retrofit with OCM

In an OCM process, methane (CH₄) reacts with an oxidizing agent over acatalyst bed to generate C₂₊ compounds. The OCM process producesolefins, such as ethylene, and can add to or replace olefin productionfrom a pyrolysis process (e.g., ethane cracking or naphtha cracking). Insome cases, a low price natural gas feedstock (used by the OCM process)makes the retrofit to the cracker (which uses expensive feedstock suchas naphtha or ethane) an attractive and economical process.

FIG. 19 illustrates how a cracker 1932 can be retrofitted (integrated)with the OCM process. Various unit operations between the blocks andcolumns are not shown for the purposes of simplification of the drawing.With reference to FIG. 19, the integrated process uses OCM effluent 1900from an OCM reactor 1902 (containing C₁, and C₂₊ type hydrocarbons) thatutilize a separation train downstream of the cracker 1932 to produceolefins 1904, such as ethylene and propylene. Natural gas 1934 is fedinto the OCM reactor, along with a source of O₂ 1936 (e.g., air orenriched oxygen). The natural gas can be de-sulfurized in a sulfurremoval unit 1938.

A lean oil absorber 1906 using light or heavy pyrolysis gas from thecracker, or any oil stream containing hydrocarbons in the C₅ to C₁₀range from refining and/or natural gas processing plants, can be used toseparate the C₁ from the C₂₊ hydrocarbons and uses all or some of theunit operations downstream of the quench tower 1908 of a typical crackerfor the cleaning and separations of the hydrocarbons.

The OCM effluent to the process gas compressor (PGC) 1910 compresses thegas to a pressure between 200-800 psia. Water present in the OCMeffluent can be removed. A mole sieve drier is a non-limiting example ofa process that may remove water from the system, but any conventionalwater removal system can be used in this system. The effluent is thencooled to between 50° F. and −80° F., in some cases between −20° F. to−60° F., (depending on C₂₊ purity required by the cracker) and sent tolean oil absorber column 1906.

The lean oil absorber 1906 can run with both a light pyrolysis gas (suchas C₅₊ pyrolysis gas) obtained from the quench tower of a typicalcracker 1912 and also a heavy pyrolysis gas (such as C₇₊ pyrolysis gas)1914 typically obtained from the heavies fractionator, such as ade-butanizer, de-pentanizer, or gasoline stripper of a cracker, orgasoline from the aromatics extraction plant (either raffinate/lightpyrolysis gasoline or the heavy pyrolysis gasoline stream).

The absorber can operate with 40-100 stages, 200-800 psia, and −80° F.to 50° F., providing C₂ recovery of 75%-100%. The ratio of the lbs ofC₁/lb ethylene from the bottoms of the absorber can be between 1.0-3.0lbs C₁/lb ethylene depending on the conditions used in the absorber. Thelean oil losses in the process are as low as 0.0004-0.001 wt % of leanoil. The ratio of lean oil to OCM effluent is between 0.5-5.5 on a massbasis.

The rich C₂₊ stream can then be sent to the PGC of the cracker 1916,treated and separated to produce olefins, such as ethylene. For example,the rich oil can be fed to the compressor's third stage discharge drum,where it can flash lights into the fourth stage suction, while theheavies can be sent to the second stage suction for further recovery oflights. Eventually the oil can be recovered in the Quench tower 1980 andsent back to the lean oil absorber. Alternatively, the rich oil can besent to a new stripping column, with the lights then sent to theappropriate suction drum of the PGC.

If the constraints of the cracker are such that a purer C₂ spec isrequired or if the demethanizer of the cracker is constrained by methaneremoval capacity, a C₁/C₂ fractionator 1918 can be added to recover60-100% of the methane from the overhead of the fractionator with a muchpurer C₂₊ stream sent to the either the demethanizer or the deethanizerof the cracker. The C₂₊ can then be separated in the separations trainto produce olefins and the C₁ sent back to the OCM as recycle C₁ 1920.Depending on the CO₂ concentration from the C₁/C₂ fractionator, acaustic wash can be used or the C₂₊ sent to the gas treating section forCO₂ removal.

The C₁/C₂ fractionator can run between 200-800 psia, and provide99.0-99.9% recovery of the methane from the C₂₊ stream. This can be sentto gas treating 1922 before separations 1924 and/or the demethanizerand/or the deethanizer in the cracker depending on the concentration ofCO₂ and C₁ in the C₂₊ stream from the fractionator.

Refrigeration power can also be recovered from the C₁ recycle stream tothe OCM depending on the conditions at which the absorber and OCM arerunning. Refrigeration power anywhere between 0.1 kilowatts (KW)/poundethylene to 1 KW/pound ethylene can be recovered.

The CO₂ 1926 from the overhead of either the absorber or thefractionator can be sent to a methanation unit 1928 in which the CO₂ andCO react with the H₂ in the presence of a catalyst to form CH₄ andrecycled back to the OCM reactor.

Natural gas produced in the demethanizer of the cracker train can besent back to the OCM unit to the methanation section. The H₂ content inthe recycle stream can be methanated in the presence of CO₂ and CO inthe methanation reactor and sent to the OCM reactor as feed natural gas.

The OCM process also produces a purge stream 1930, with a heating valuein the range of 800 BTU/SCF to 1000 BTU/SCF that can be used as fuelgas, make-up or otherwise. Additional natural gas may also be fed to thecracker furnace through streams 1920 before methanation of the C₁recycle, or stream 1944 after methanation (such as, e.g., depending oncracker requirements), to provide fuel gas since the fuel oil isutilized in a more efficient manner of producing olefins. The presentexample shows how olefins 1904 can be produced from both natural gas1934 and cracker feed 1940 (e.g., as shown in FIG. 19).

In some cases, the cracker 1932 generates ethane in addition to olefins.The ethane can be recycled to an ethane conversion section of the OCMreactor 1902 for conversion to olefins.

Control Systems

The present disclosure provides computer control systems that can beemployed to regulate or otherwise control OCM methods and systemsprovided herein. A control system of the present disclosure can beprogrammed to control process parameters to, for example, effect a givenproduct distribution, such as a higher concentration of alkenes ascompared to alkanes in a product stream out of an OCM reactor.

FIG. 20 shows a computer system 2001 that is programmed or otherwiseconfigured to regulate OCM reactions, such as regulate fluid properties(e.g., temperature, pressure and stream flow rate(s)), mixing, heatexchange and OCM reactions. The computer system 2001 can regulate, forexample, fluid stream (“stream”) flow rates, stream temperatures, streampressures, OCM reactor temperature, OCM reactor pressure, the quantityof products that are recycled, and the quantity of a first stream (e.g.,methane stream) that is mixed with a second stream (e.g., air stream).

The computer system 2001 includes a central processing unit (CPU, also“processor” and “computer processor” herein) 2005, which can be a singlecore or multi core processor, or a plurality of processors for parallelprocessing. The computer system 2001 also includes memory or memorylocation 2010 (e.g., random-access memory, read-only memory, flashmemory), electronic storage unit 2015 (e.g., hard disk), communicationinterface 2020 (e.g., network adapter) for communicating with one ormore other systems, and peripheral devices 2025, such as cache, othermemory, data storage and/or electronic display adapters. The memory2010, storage unit 2015, interface 2020 and peripheral devices 2025 arein communication with the CPU 2005 through a communication bus (solidlines), such as a motherboard. The storage unit 2015 can be a datastorage unit (or data repository) for storing data.

The CPU 2005 can execute a sequence of machine-readable instructions,which can be embodied in a program or software. The instructions may bestored in a memory location, such as the memory 2010. Examples ofoperations performed by the CPU 2005 can include fetch, decode, execute,and writeback.

The storage unit 2015 can store files, such as drivers, libraries andsaved programs. The storage unit 2015 can store programs generated byusers and recorded sessions, as well as output(s) associated with theprograms. The storage unit 2015 can store user data, e.g., userpreferences and user programs. The computer system 2001 in some casescan include one or more additional data storage units that are externalto the computer system 2001, such as located on a remote server that isin communication with the computer system 2001 through an intranet orthe Internet.

The computer system 2001 can be in communication with an OCM system2030, including an OCM reactor and various process elements. Suchprocess elements can include sensors, flow regulators (e.g., valves),and pumping systems that are configured to direct a fluid.

Methods as described herein can be implemented by way of machine (e.g.,computer processor) executable code stored on an electronic storagelocation of the computer system 2001, such as, for example, on thememory 2010 or electronic storage unit 2015. The machine executable ormachine readable code can be provided in the form of software. Duringuse, the code can be executed by the processor 2005. In some cases, thecode can be retrieved from the storage unit 2015 and stored on thememory 2010 for ready access by the processor 2005. In some situations,the electronic storage unit 2015 can be precluded, andmachine-executable instructions are stored on memory 2010.

The code can be pre-compiled and configured for use with a machine havea processer adapted to execute the code, or can be compiled duringruntime. The code can be supplied in a programming language that can beselected to enable the code to execute in a pre-compiled or as-compiledfashion.

Aspects of the systems and methods provided herein, such as the computersystem 2001, can be embodied in programming. Various aspects of thetechnology may be thought of as “products” or “articles of manufacture”typically in the form of machine (or processor) executable code and/orassociated data that is carried on or embodied in a type of machinereadable medium. Machine-executable code can be stored on an electronicstorage unit, such memory (e.g., read-only memory, random-access memory,flash memory) or a hard disk. “Storage” type media can include any orall of the tangible memory of the computers, processors or the like, orassociated modules thereof, such as various semiconductor memories, tapedrives, disk drives and the like, which may provide non-transitorystorage at any time for the software programming. All or portions of thesoftware may at times be communicated through the Internet or variousother telecommunication networks. Such communications, for example, mayenable loading of the software from one computer or processor intoanother, for example, from a management server or host computer into thecomputer platform of an application server. Thus, another type of mediathat may bear the software elements includes optical, electrical andelectromagnetic waves, such as used across physical interfaces betweenlocal devices, through wired and optical landline networks and overvarious air-links. The physical elements that carry such waves, such aswired or wireless links, optical links or the like, also may beconsidered as media bearing the software. As used herein, unlessrestricted to non-transitory, tangible “storage” media, terms such ascomputer or machine “readable medium” refer to any medium thatparticipates in providing instructions to a processor for execution.

Hence, a machine readable medium, such as computer-executable code, maytake many forms, including but not limited to, a tangible storagemedium, a carrier wave medium or physical transmission medium.Non-volatile storage media include, for example, optical or magneticdisks, such as any of the storage devices in any computer(s) or thelike, such as may be used to implement the databases, etc. shown in thedrawings. Volatile storage media include dynamic memory, such as mainmemory of such a computer platform. Tangible transmission media includecoaxial cables; copper wire and fiber optics, including the wires thatcomprise a bus within a computer system. Carrier-wave transmission mediamay take the form of electric or electromagnetic signals, or acoustic orlight waves such as those generated during radio frequency (RF) andinfrared (IR) data communications. Common forms of computer-readablemedia therefore include for example: a floppy disk, a flexible disk,hard disk, magnetic tape, any other magnetic medium, a CD-ROM, DVD orDVD-ROM, any other optical medium, punch cards paper tape, any otherphysical storage medium with patterns of holes, a RAM, a ROM, a PROM andEPROM, a FLASH-EPROM, any other memory chip or cartridge, a carrier wavetransporting data or instructions, cables or links transporting such acarrier wave, or any other medium from which a computer may readprogramming code and/or data. Many of these forms of computer readablemedia may be involved in carrying one or more sequences of one or moreinstructions to a processor for execution.

EXAMPLES

Below are various non-limiting examples of uses and implementations ofOCM catalysts and systems of the present disclosure.

Example 1 Implementation of OCM

About 1,000,000 metric tons/year of polymer grade ethylene is producedvia the oxidative coupling of methane (OCM). The OCM reactor comprises a2-stage adiabatic axial fixed bed that utilizes an OCM catalyst (e.g.,nanowire catalyst) to convert methane and high purity oxygen toethylene. The methane feed to the OCM reactor is the recycle stream froma downstream demethanizer over-head supplemented by CO and CO₂conversion to methane in a two-stage methanation reactor. The hot OCMeffluent from a second stage of the reactor effluent is mixed withheated recycle ethane from a downstream C₂ splitter and cracked toconvert ethane primarily into ethylene. Hot reactor effluent is used toheat OCM reactor feed, generate high-pressure steam and heat processcondensate. Cold reactor effluent is compressed and mixed withsulfur-free pipeline natural gas and treated to remove CO₂ and H₂O priorto cryogenic separations. The treated process gas is fed to ademethanizer column to recover about 99% of ethylene as column bottomsstream. Demethanizer bottoms steam is separated in deethanizer column toseparate C₂'s from C₃₊ components. Deethanizer column overhead is firsttreated in selective hydrogenation unit to convert acetylene intoethylene and ethane using H₂ from a Pressure Swing Adsorption (PSA)Unit. The resulting stream is separated in a C₂ splitter unit toseparate ethylene from ethane. Deethanizer bottoms stream is sent to aDe-propanizer to obtain Refinery Grade Propylene (RGP) and mixed C₄₊stream, both which can be sold for credit. Ethane product stream from C₂splitter bottoms is recycled to second stage of the OCM reactor tocomplete extinction. Polymer grade ethylene product (99.96 wt %ethylene) obtained from the C₂ splitter overhead is compressed to 1,000psig and exported as vapor product. A stream factor of 0.95 is used(equal to an installed capacity of 1,059,000 metric tons/yr).

The OCM process generates superheated high pressure (˜1500 psia) steamthat is used to run process gas compressors, refrigeration compressors,ethylene heat pump/product compressors, and major pumps. The remainderof the steam and small portion of recycle methane (purge gas) can beexported to combined cycle/gas turbine system to generate power. The OCMprocess has an energy intensity of −0.89 MMBTU/MT ethylene, while theenergy intensity of a comparably sized steam cracking of ethane processis about 31.89 MMBTU/MT.

The reactor consists of a 2-stage adiabatic axial fixed bed withintermediate heat recovery via high-pressure steam generation. Themethane stream recycled from the demethanizer overhead becomes the mainOCM reactor feed. In both stages high purity oxygen is mixed with thehydrocarbon stream in a proportion of approximately 1:10 on a molarbasis to achieve the optimal O₂-limited composition for the OCMreaction.

In the OCM reactor, the catalyst enables the partial and highlyselective conversion of methane to, primarily, ethylene and ethane, withminor amounts of propylene and propane. Non-selective pathways includehigh temperature hydrocarbon reactions, such as combustion, reformingand shift. The second stage of the reactor is designed to accommodate anethane conversion zone immediately downstream of the catalytic bed.Ethane recycled from the deethanizer and, optionally, additional freshethane feed are injected into this reactor section where ethaneundergoes highly selective adiabatic thermal de-hydrogenation toethylene.

The OCM reactor effluent flows through a series of heat exchangers toachieve optimal heat recovery and final condensation at ambienttemperature, prior to being sent to the Process Gas Compressor (PGC).The natural gas feed stream is mixed with the OCM reactor effluent atthe PGC delivery. Gas treating, including CO₂ removal and drying,follows the compression step. The product recovery train consists of ademethanizer, deethanizer, acetylene converter and C₂ splitterconfiguration where the refrigeration and heat integration scheme isdesigned to optimize heat recovery and minimize power consumption. Theproduct streams comprise of polymer grade ethylene and a C₃₊ mixedstream, similar in composition to Refinery Grade Propylene (RGP), whichcan be optionally further separated and purified. The C₁ recycle streamleaving the demethanizer head is sent to a conventional methanation unitwhere all CO and a portion of the CO₂ product react with hydrogen toform methane. The integration of the methanation unit into the overallprocess design is instrumental to maximize the carbon efficiency of theOCM technology.

The OCM process design is energy neutral. The OCM reaction heat isutilized to provide mechanical power to the rotating units required forcompression and pumping. The OCM process gets pure oxygen from anadjacent Air Separation Unit (ASU) which also houses a Gas TurbineCombined Cycle (GTCC). The GTCC unit is fed with the purge gas extractedfrom the demethanizer overhead and provides all the mechanical power andsteam required by the ASU.

The final products are 1,000,000 metric tons per annum of polymer gradeethylene and 88,530 metric tons per annum of C³⁻ hydrocarbons. The C₃₊hydrocarbons are sent to a depropanizer to obtain refinery gradepropylene (65% propylene) as distillate.

Example 2 Design Basis of OCM Implementation

The feedstock streams can include a natural gas stream, which suppliesthe process with the methane and ethane for conversion into ethylene, anoxygen stream, to be supplied by the dedicated Air Separation Unit (ASU)section, an optional ethane stream, which provides extra ethane (inaddition to that contained in the natural gas feed) for conversion intoethylene.

As shown in FIG. 21, the ethylene product plant comprises four sectionsincluding an OCM reaction section 2100 (comprising methanation, OCM andheat recover), a process gas compression and treating section 2105(comprising PGC, CO2 removal and drying), a product separation andrecovery section 2110 (comprising demethanizer, deethanizer, C₂ splitterand depropanizer) and a refrigeration system 2115 (comprising propyleneand ethylene). The process takes in natural gas 2120, which can bedesulfurized. The process can take in oxygen 2125 from an air separationunit. Ethane can be added externally 2130 or as part of a C₂ recycle2135. The purge gas 2140 can contain C₁ compounds and can be recycled2145. Products can include ethylene 2150, C₄₊ compounds 2155 and RGP2160.

Unlike at least some syngas based production processes, the presentprocess is flexible in terms of quality and composition required for thenatural gas stream. For example, the process can handle an extremelywide range of natural gas liquids concentration, in particular ethane.None of the typical contaminants present in natural gas, includingsulfur, represents a poison for the OCM catalyst. Prior to entering theprocess, the natural gas feed is treated for sulfur removal in order toprevent contamination of the process outputs and sulfur accumulation inthe process. The desulfurization scheme adopted is hydrotreating in aCo/Mo catalyst bed followed by adsorption on a zinc oxide bed. Dependingon the actual sulfur content and composition, the adsorption bed may bethe only operation. Alternatively other conventional methods of sulfurremoval may be used.

The source of the oxygen for the OCM reaction can be air or pure oxygenor any enriched air stream. The presence and concentration of nitrogenmay not impact the performances of the OCM reactor system. However,under certain conditions, utilizing pure oxygen as delivered by aconventional Air Separation Unit may minimize the overall processproduction costs at large scale. Alternatively, enriched air producedvia a PSA or air sourced via a compressor may provide the optimaleconomic solution under other large scale applications.

The OCM reactor has the capability of efficiently processing separatestreams of methane and ethane. In the process, the methane stream comesfrom the demethanizer overhead while the ethane stream, which includesboth the unconverted ethane and the ethane contained in the natural gasfeed, comes from the deethanizer bottom. Depending on the actual ethanecontent in natural gas there may be additional ethane processingcapacity available in the OCM reactor, which can be saturated with afresh ethane feed directly mixed with the ethane recycle.

In the particular US Gulf Coast based case presented herein, the naturalgas feed is relatively lean (˜4.5% mol ethane), thus additional ethanefeed is considered to exploit the available reactor capacity andoptimize the overall process economics.

A generic process layout for an ethylene plant based on informationdescribed in U.S. Patent Publication No. 2014/0012053 and PCT PatentApplication No. US/2013/042480, each of which is herein incorporated byreference in its entirety. The process configurations presented hereinare illustrative of a commercial system designed to produce high purity(e.g., 99.96 wt % purity) ethylene via oxidative coupling of methane.

As described in Example 1, the plant is sized to produce at least1,000,000 metric ton/year (2,214 million lb/yr) of polymer gradeethylene at an on-stream factor of 0.95. Hence, the annual installedcapacity is equivalent to 1,059,000 metric t/year (2,330 million lb/yr).The plant also produces 61,185 metric ton/year of refinery grade (65%)propylene and 27,345 metric ton/year of C₄₊ compounds. The reactorsystem is a 2-stage adiabatic axial fixed bed with intermediate heatrecovery via high pressure steam generation; OCM nanowire catalyst withbed height=8.3 ft.; 12″ refractory lining; 2^(nd) stage bottom sectionused for ethane cracking; and a 2-stage adiabatic methanation unit toconvert CO and CO₂ recycle into methane. The feedstock is pipelinenatural gas, 99.5% oxygen (fed in 1:10 molar basis with hydrocarbonstream), and make-up ethane. The operating conditions include OCMreactor inlet conditions: 540° C. (1004° F.), 131 psia; OCM reactor exittemperature: 830° C. (1525° F.); and methanation reactor inletconditions: 200° C. (392° F.), 161 psia. The overall conversion is21.5%, which includes conversion of methane and ethane to all reactionproducts across the OCM reactor. The carbon efficiency is 71% for theISBL process (specifies carbon utilization for all ISBL units) and 64%overall (includes energy consumption to run OSBL units (mainly ASU)).The selectivity for each reaction product across the OCM reactor is:55.9% for C₂H₄; 2.2% for C₃H₆; 9.7% for CO; 31.3% for CO₂; and 0.9% forothers.

Example 3 Catalyst Preparation and Catalyst Life

The catalyst is made according to U.S. patent application Ser. Nos.13/115,082, 13/479,767, 13/689,514 13/757,036 and 13/689,611, andPCT/US2014/028040 filed on Mar. 14, 2014 each of which is entirelyincorporated herein by reference. The catalyst is based upon mixed metaloxide catalysts. In some cases, the mixed metal oxide catalysts arecomprised of nanowires, mixtures of nanowires and bulk metal oxides, orbulk catalysts. The OCM catalysts can be synthesized via a reactionsimilar to a standard co-precipitation reaction that takes place in anaqueous solution. The catalysts are then filtered out of the solution,and the resulting solids are calcined.

In order to produce a commercial catalyst, the calcined powder is thenmixed with catalyst diluents and binders and formed into commercialforms. Catalyst forming tools are then used to form the combined powder,diluents, and binders into solid cylinders (or other shapes, such asspheres, rings, etc.) with the requisite strength and performancerequirements. See, e.g., WO2013177461, which is entirely incorporatedherein by reference. Such forming can take place via extrusion ortableting or other conventional catalyst forming techniques. FIG. 22shows an image of the formed cylindrical commercial OCM catalyst. FIG.23 and FIG. 24 show Scanning Electron Microscope images of a magnifiedportion of the commercial catalyst. FIG. 23 and FIG. 24 show the entire,formed catalyst with nanowires incorporated along with diluents andbinders. The white bar in each of the figures designates a scale bar of5 micrometers (microns).

Under the operating conditions described within this application, an OCMcatalyst is stable, with a minimum lifetime of at least 1 year, 2 years,3 years, 4 years, 5 years, 6 years, 7 years, 8 years, 9 years, 10 years,or 20 years. An OCM catalyst can be regenerated in-situ or regeneratedex-situ. Alternatively, instead of regeneration, an OCM catalyst can beunloaded and returned to the catalyst manufacturer. There, it can berecycled to reclaim its constituent elemental components, or,alternatively, disposed of.

Example 4 OCM Reactors and Reaction Systems

The OCM reactor contains two reaction zones. The entire reactor is arefractory-lined adiabatic reactor. The first reaction zone contains afixed OCM catalyst bed, to convert methane into ethylene. This is calledthe methane conversion zone. In the lower section of the reactor, ethaneis injected to homogeneously convert ethane to ethylene utilizing theheat generated during methane conversion. This is called the ethaneconversion zone. The introduction of reactants into the OCM reactorsystem is achieved using, extremely low residence time gas mixers. Thisallows the reactants to be introduced at elevated temperatures, withoutparticipating in non-selective side reactions.

In the adiabatic OCM reactor system, the temperature is allowed to risewithin a reactor stage through the catalytic bed (methane conversionzone), from approximately 460° C., 470° C., 480° C., 490° C., 500° C.,510° C., 520° C., 530° C., 540° C., 550° C., 560° C., 570° C., 580° C.,590° C., or 600° C. at the inlet to about 850° C., 860° C., 870° C.,880° C., 890° C., 900° C., 910° C., 920° C., 930° C. at the outlet ofthe bed. Ethane at a lower inlet temperature (about 400° C.-500° C.) isinjected into the ethane conversion zone to allow for additionalnon-oxidative dehydrogenation to take place thereby cooling the reactoreffluent. A representative temperature profile of the entire reactor isshown in FIG. 25. The reactor has a methane conversion section (e.g.,for OCM) and an ethane conversion section (e.g., for conversion ofethane to ethylene).

In some cases, performance of the process in terms of overall carbonefficiency is higher than that of the OCM reactor alone. The highercarbon efficiency derives from the presence of the catalytic methanationstep, which converts all CO and a portion of the CO₂ product back tomethane by utilizing the hydrogen generated in the thermal ethaneconversion zone of the OCM reactor.

The methanation unit is a 2-stage adiabatic reaction system, whichadopts the same or similar process technology used for Synthetic NaturalGas (SNG) production from syngas. The methanation section is designed tomaximize hydrogen consumption and, thus, CO and CO₂ recovery to methane.Alternative process configurations may include the use of an isothermalreactor in place of the 2-stage adiabatic system.

The design basis also illustrates the impact of the outside batterylimits (OSBL) units (mainly the Air Separation Unit) on the overallcarbon and energy balance. In the process the purge gas from thedemethanizer overhead fuels the GTCC unit, which is used to provide themechanical power required by the ASU and make the entire process energyneutral.

With reference to FIGS. 26-31, the OCM Reaction System includes twoconversion steps: i) the 2-stage OCM Reactor (R-101A&B 2650 and R-102A&B2651) that converts the methane and ethane recycle streams intoethylene; and ii) the 2-stage Methanation Reactor (R-103 2652 & R-1042653) that converts the CO and H₂ present in the methane recycle (andsome additional CO₂) into methane. A series of feed-product economizers,steam generator and super-heater, BFW pre-heater and cooling waterexchangers is also included in this process area to provide optimal heatrecovery

The methane recycle feed stream 2621 coming from the Demethanizer headis first pre-heated to 116° C. (240° F.) in the cross exchanger (E-110)2661 with the hot effluent from the 2^(nd) stage of OCM reactor and thenfurther heated to approximately 200° C. (392° F.) in the MethanatorFeed/Product Exchanger (E-101) 2654. This methane stream is then sent to1^(st) stage (R-103) 2652 of the methanation unit where CO is almostcompletely converted to methane in presence of an excess of hydrogen.Methanation is an exothermic reaction limited by equilibrium and it iscarried out over a suitable hydrogenation catalyst in a fixed bedadiabatic reactor. R-103 2652 effluent 2602 is cooled in E-101 2654against R-103 2652 feed, mixed with additional CO₂ coming from CO₂removal unit and then fed to the 2^(nd) stage (R-104) 2653 ofmethanation. In R-104, H₂ is the limiting reactant and is almostcompletely converted in the reaction.

R-104 effluent 2603 is further pre-heated in the Hot Gas-Gas Exchanger(E-102) 2655 to achieve the OCM reactor inlet temperature of 540° C.(1004° F.). It is then fed to the 1^(st) stage (R-101) 2650 of the OCMReactor to undergo OCM conversion to ethylene. In R-101 2650 thepre-heated methane feed stream is mixed with the part of the oxygensupplied by the Air Separation Unit 2605. The mixed feed flows over theOCM catalytic bed and leaves R-101 2650 at a temperature ofapproximately 830° C. (1525° F.). The reaction heat generated in the1^(st) stage is recovered in the steam generator (E-103) 2656 bygenerating high pressure (1500 psia) steam. The high pressure streamfrom E-103 2656 is further superheated to 476° C. (889° F.) in exchangerE-104 2657.

R-101 2650 effluent is then fed to the 2^(nd) stage (R-102 A&B) 2651 ofthe OCM reactor. It is again mixed with oxygen and fed to the OCMcatalyst to carry out the OCM reactions. The ethane feed stream 2606comprising of the ethane recycle 2634 from the C₂ splitter bottoms andmake-up ethane 2601 is first preheated in the Ethane Gas-Gas Exchanger(E-107 2658) and then injected into the bottom section of R-102 2651immediately downstream of the OCM catalytic bed to undergo thermalde-hydrogenation to ethylene.

R-102 2651 effluent at approximately 830° C. (1528° F.) is sent to theSteam Generator and Super-Heater Unit, E-106 2657, respectively wherethe reaction heat generated in the 2^(nd) stage is optimally recovered.The product stream leaving E-106 2657 flows through the Ethane and theHot Gas-Gas Exchangers, prior to entering the Boiler Feed Water (BFW)Pre-Heater (E-108) 2659. The low temperature fraction of the reactionheat is recovered first in the BFW Pre-Heater E-108 2659 and then in theSteam Condensate Pre-Heater E-109 2660. The product gas leaving 2660flows into the Cold Gas-Gas Exchanger (E-110) 2661 prior to injectioninto the Quench Tower-I (C-101) 2662.

In the Quench Column (C-101) 2662, the product gas is further cooled toambient temperature and a significant portion of the water produced inthe OCM reactors is condensed and separated as Process Condensates 2608.The C-101 2662 overhead gas stream 2607 is sent to Process GasCompression and Treating.

Example 5 OCM Process Gas Compression and Treating

The process gas compressor discharge pressure is set to 540 psia tomaintain the downstream process gas circuit to a single train withcolumn and vessel sizes limited to a maximum 25 feet diameter. However,the demethanizer can operate as low as 175 psia. This can significantlyreduce process gas compression requirements, but requires parallelprocess gas treatment and demethanizer unit trains and larger propyleneand ethylene refrigerant systems. All tradeoffs between capital expense(CAPEX) and operating expense (OPEX) are resolved in a manner thatmaximizes overall financial return.

Process gas is treated to remove carbon dioxide and water to 0.5 ppmvprior to cryogenic separations using a monoethanol amine-based unitfollowed by a two-stage caustic wash. Molecular sieve dryers areutilized to remove all moisture from the treated process gas.

With reference to FIGS. 26-31, the Process Gas Compression & Treatingsection is comprised of four main units: i) The 2-stage (K-201A&B 2665and K-202 2666) Process Gas Compressors (PGC); ii) a natural gasdesulfurization unit 2667; iii) the CO₂ removal Unit 2668, including anamine-based absorber and a caustic wash column (G-201); and iv) a dryingunit based on molecular sieves absorption (M-201 A-C) 2669.

Process gas from the Quench Column C-101 2662 is compressed in the2-stage PGC unit (K-201 2665 & 202 2666) to a final pressure of 540psia. The compressed process gas delivered by K-202 2666 is mixed withthe desulfurized natural gas feed stream 2615 and sent to the Aminesystem unit (G-201) 2668. Pipeline natural gas is first sent through aknockout (KO) drum (V-201) 2670, pre-heated to 260° C. (500° F.) inexchanger (E-201) 2671 against the hot desulfurization reactor (R-201)2672 effluent 2615 and further heated to 316° C. (600° F.) in a processfurnace (F-201) 2673 before entering R-201 2672. The reactor R-201 2672consists of two beds: the top bed consists of a standard Co/Mo catalystto convert the sulfur species to H₂S and a bottom ZnO bed to adsorb it.The treated natural gas is sent through a turboexpander (S-201) 2674 torecover some energy.

The rich amine stream leaving the amine absorber bottom is first flashedat an intermediate pressure in the CO₂ Flash Drum. The CO₂ vaporsleaving flash drum 2617 are sent to the methanation unit, as describedin the previous section. The liquid bottoms leaving flash drum areheated against the lean amine from the Amine Regeneration Columns in theLean-Rich Solution Exchanger. Medium pressure steam is used to providethe necessary heat for the Regeneration Columns Reboilers. TheRegeneration column overhead vapor is cooled and then washed withprocess water to remove any residual amines prior to CO₂ venting 2618 toatmosphere. The overhead process gas from the CO₂ Absorber is furthertreated in the Caustic Wash Column, which consists of two stages (richand lean caustic wash), followed by water-wash stage. The treatedprocess gas from Caustic Wash Column 2616 is cooled in exchangers, E-2042675 and E-205 2676, against the methane recycle 2623 and H2 recycle2624 streams from the demethanizer, respectively, and then separated inthe Knock-Out Drum V-202 2677. The methane recycle streams afterexchanging heat through E-204 2675, receives part of the H₂ recycle andthe PSA purge stream 2631, before being split into the purge gas stream2620 and C₁ recycle stream 2621. The purge gas can be sold for credit oralternatively sent to the Gas Turbine Combined Cycle (GTCC) unit housedin an adjacent Air Separation Unit (ASU) to generate mechanical power.Part of the H₂ recycle stream is sent to the PSA unit 2622 to recoverhydrogen for NG desulfurization in R-201 2672 and Acetylenedehydrogenation in R-301.

The process gas leaving V-202 2677 is then fed to the Molecular SieveGas Dryers (M-201A-C) 2669 where all moisture present in the vapors isremoved. The dried process gas is then routed to product separation andrecovery.

Example 6 OCM Process Gas Separations

The cryogenic separation section of this example utilizes demethanizerand deethanizer technology, but refrigeration is supplemented byexpansion-cooling of the olefin-rich process gas as explained in U.S.patent application Ser. No. 13/739,954, which is herein incorporated byreference in its entirety. By utilizing these methods, the amount ofrefrigeration provided by propylene and ethylene can be reduced, whichprovides substantial energy savings.

The treated process gas is separated through a demethanizer,deethanizer, ethylene fractionator (C₂ splitter) and de-propanizer.Treated process gas is cooled using the demethanizer unit overheadproduct streams and side reboiler and the remainder of the cooling dutyis provided by propylene and ethylene refrigeration. The demethanizerrecovers 99% of the contained ethylene. The bottoms of the demethanizerare sent to the deethanizer. The overall heat integration scheme for thedemethanizer cooling is an aspect of the present disclosure. It includesthe adoption of a split vapor process scheme, where a portion of thedemethanizer overhead vapor is compressed and then expanded to providethe necessary reflux to the demethanizer. The remaining vapor streamsare sent to a turbo-expander to recover refrigeration value and thenrecycled to the OCM reactor.

The balance between the demethanizer operating pressure, the amount ofcooling produced by the internal split vapor scheme and the amount ofrefrigeration provided by external units constitutes an area ofoptimization for the trade-off between CAPEX and OPEX. The deethanizerunit is a separation column designed for an ethane recovery of 99 mol %.Deethanizer unit bottoms stream is further fractionated in ade-propanizer to recover a Refinery Grade Propylene (RGP) product streamand a C₄ mix product stream.

The deethanizer overhead stream is treated for acetylene and fed to theC₂ splitter, a heat pumped fractionator system. The overhead vapor iscompressed and used to provide hot vapor for the reboiler. Liquid fromthe reboiler is then used to provide refrigerant for the condenser. TheC₂ splitter can have a few trays that serve as a pasteurizing section toremove most of the hydrogen or other inerts that enter the C₂ splitterunit from the acetylene converter. The C₂ splitter can recover 99% ofthe contained ethylene with a purity of 99.95 mol %. The bottoms productis ethane and is recycled back to ethane conversion section of the OCMreactor.

With reference to FIGS. 26-31, the process gas stream 2619 leaving theGas Dryers M-201A-C 2669 is routed to the first cold box E-301 2678 andcooled against a series of cold streams coming from the Demethanizersystem and from the external refrigeration units. The cooled gas streamleaving E-301 2678 is fed to the Demethanizer Column C-301 2679, wherethe C₂₊ compounds are separated from the lighter components of theprocess gas (primarily CH₄, CO and H₂). The Demethanizer Column overheadproducts 2624 and 2625 are re-heated against the Demethanizer Columnfeed and recycled to the OCM Reaction System.

The overhead reflux necessary for the proper operation of theDemethanizer Column C-301 2679 is generated via a proprietaryrefrigeration process scheme, known as the Recycle Split Vapor Unit(G-301) 2680 that minimizes the need for external refrigeration input.The C-301 2679 bottom stream 2626 consists of ethane, ethylene,acetylene and a small fraction (˜5.4%) of heavier (C₃₊) components. Thisliquid stream is sent to the Deethanizer Column (C-302) 2681. TheDeethanizer Column (C-302) 2681 separates the C₃₊ components in theC-302 2681 feed from the C₂ components with minimum loss of ethylene inthe C₃₊ stream. C-302 2681 bottoms stream 2627 represents the mixed C₃₊product stream which is sent to a Depropanizer (C-304) 2682. Refinerygrade propylene (RGP) (˜65% propene) is obtained as C-304 2682distillate stream 2635 and is sent to the appropriate distributionsystem to obtain by-product credit. Similarly, C-304 2682 bottoms stream2636 contains a mixed C₄₊ stream that can be sold.

The C-302 2681 overhead stream is cooled in a partial condenser (E-304)2683 using propene refrigeration. Liquid condensate is sent as reflux toC-302 2681. C-302 2681 overhead vapor product 2628 is then heated inE-302 2684 and routed to a two-stage acetylene hydrogenation reactorR-301 2685 where all acetylene is hydrogenated to ethylene and ethane.

A pressure swing adsorption (PSA) unit (G-302) 2686 is installed on aslip stream of the demethanizer overhead vapors to produce thehigh-purity hydrogen stream required by the acetylene hydrogenationreactor (R-301) 2685. The acetylene reactor operates at low temperatures(100° F. Start of run and 150° F. End of run) using a selectivepalladium catalyst to convert acetylene to ethylene and ethane. R-3012685 effluent 2632 is cooled and sent to the Ethylene Splitter (C-303)2687. C-303 2687 produces a 99.96 wt % pure ethylene overhead product2633 and a 99% pure ethane stream 2634 as bottoms. A cold box (E-306)2688 serves as the C-303 2687 condenser and reboiler. A heat pumpcompressor K-302 2689 provides hot ethylene vapor to the C-303 reboilerafter looping once through the condenser. The condensed ethylene liquidfrom the reboiler is used in the C-303 condenser.

The high-pressure ethylene product 2633 from K-302 2689 is sent to therelevant distribution system. The C-303 bottoms 2634 are recycled to OCMreaction and injected into the 2^(nd) stage R-102 2651 of the OCMReactor.

Example 7 Refrigeration and Steam Generation

The system consists of propylene and ethylene refrigeration systems.Propylene refrigeration system is a three-stage refrigeration system,with three different coolant levels, as illustrated in FIG. 30.Additional utilities are shown in FIG. 31.

Evaporating ethylene from the propylene refrigeration cycle is used tocondense the ethylene in the ethylene refrigeration cycle and providerefrigerant to the deethanizer overhead condenser (E-304 2683) and thedemethanizer cold box (E-301 2678).

Ethylene refrigeration system is also a three-stage refrigeration systemas illustrated in FIG. 30. This system provides refrigeration to thedemethanizer cold box (E-301 2678) and to the Recycle Split Vapor Unit(RSV 2680).

Superheated, high pressure (HP) steam (1500 psia, 889° F.) generated bythe OCM process is used to drive the process gas compressor, thedemethanizer overhead compressor, the refrigeration compressors, theethylene fractionator heat pump and product compressors, half of coolingwater and boiler feed water pumps (in offsites), and is fed to mediumpressure (MP, 165 psia) and low pressure (LP, 50 psia) reboilers afterproper flashing and de-superheating. Any remaining steam can be exportedto the Gas Turbine Combined Cycle (GTCC) unit housed in an adjacent AirSeparation Unit (ASU) that provides 99.5% O₂ for the OCM reaction. Apurge gas stream is also sent to the GTCC unit to generate themechanical power required by the ASU unit. In this review, excess steamand purge gas account for utility and by-product credit, respectively

Example 8 Stream Compositions

Table 1 shows the total flow-rate and flow rates of selected molecularentities (e.g., Hydrogen and Argon) for select streams of the exampleprocess. Stream numbers correspond to those of Examples 4-7 and FIGS.26-31.

TABLE 1 Stream flow rates 2008 2007 2006 2005 2004 2003 2002 2001 Stream# 581.1 3264.1 209.0 843.6 8304.9 2792.4 2694.7 65.8 Total (1000 lb/hr)0.0 1908.7 0.0 0.0 1909.0 2348.8 2320.7 0.0 Methane 0.0 268.9 2.7 0.0268.9 0.0 0.0 0.0 Ethylene 0.0 102.8 202.6 0.0 102.7 2.5 2.5 62.0 Ethane0.0 3.7 0.0 0.0 3.7 0.0 0.0 0.0 Acetylene 0.0 10.4 0.0 0.0 10.4 0.0 0.00.0 Propene 0.0 0.4 3.8 0.0 0.4 0.0 0.0 3.8 Propane 0.0 4.5 0.0 0.0 4.50.0 0.0 0.0 C₄₊ Compounds 581.0 39.0 0.0 0.0 620.0 123.1 58.7 0.0 H₂O0.0 37.7 0.0 0.0 37.6 2.0 16.2 0.0 Hydrogen 0.0 47.7 0.0 1.1 47.7 46.646.6 0.0 Argon 0.0 252.9 0.0 3.0 252.9 249.9 249.9 0.0 Nitrogen 0.0 0.00.0 839.6 0.0 0.0 0.0 0.0 Oxygen 0.0 93.6 0.0 0.0 93.6 0.0 0.0 0.0 CO0.0 493.9 0.0 0.0 493.5 19.2 0.0 0.0 CO₂ 2017 2016 2015 2014 2013 20122011 2010 2009 Stream # 97.7 3181.9 460.1 458.5 457.9 5.1 3691.5 27.53238.1 Total (1000 lb/hr) 0.0 2303.4 395.0 394.7 394.7 0.0 2303.4 0.01908.7 Methane 0.0 269.0 0.0 0.0 0.0 0.0 269.0 0.0 269.0 Ethylene 0.0138.7 35.9 35.9 35.9 0.0 138.7 0.0 102.8 Ethane 0.0 3.7 0.0 0.0 0.0 0.03.7 0.0 3.7 Acetylene 0.0 10.4 0.0 0.0 0.0 0.0 10.4 0.0 10.4 Propene 0.05.5 5.1 5.1 5.1 0.0 5.5 0.0 0.4 Propane 0.0 7.3 2.8 2.8 2.8 0.0 7.3 0.04.5 C₄₊ Compounds 1.3 7.9 1.2 0.0 0.0 5.1 7.9 27.5 12.9 H₂O 0.0 38.2 0.50.5 0.0 0.0 38.2 0.0 37.7 Hydrogen 0.0 47.7 0.0 0.0 0.0 0.0 47.7 0.047.7 Argon 0.0 256.6 3.7 3.7 3.7 0.0 256.6 0.0 252.9 Nitrogen 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 Oxygen 0.0 93.6 0.0 0.0 0.0 0.0 93.6 0.093.6 CO 96.4 0.0 15.7 15.7 15.7 0.0 509.6 0.0 493.9 CO₂ 2026 2025 20242023 2022 2021 2020 2019 2018 Stream # 432.2 647.7 2094.2 6.1 34.52694.7 45.3 3174.1 424.4 Total (1000 lb/hr) 0.0 488.9 1814.5 0.0 26.12268.5 0.0 2303.4 0.0 Methane 266.6 0.2 2.2 0.0 0.0 2.4 0.0 269.0 0.0Ethylene 138.7 0.0 0.0 0.0 0.0 0.0 0.0 138.7 0.0 Ethane 3.7 0.0 0.0 0.00.0 0.0 0.0 3.7 0.0 Acetylene 10.4 0.0 0.0 0.0 0.0 0.0 0.0 10.4 0.0Propene 5.5 0.0 0.0 0.0 0.0 0.0 0.0 5.5 0.0 Propane 7.3 0.0 0.0 0.0 0.00.0 0.0 7.3 0.0 C₄₊ Compounds 0.0 0.0 0.0 6.1 0.0 0.0 0.0 0.0 12.1 H₂O0.0 18.1 20.2 0.0 1.0 36.0 1.1 38.2 0.0 Hydrogen 0.0 14.9 32.8 0.0 0.846.6 6.7 47.7 0.0 Argon 0.0 92.8 163.8 0.0 4.9 249.9 0.0 256.6 0.0Nitrogen 0.0 0.0 0.0 0.0 0.0 0.0 2.4 0.0 0.0 Oxygen 0.0 32.9 60.8 0.01.8 91.3 0.0 93.6 0.0 CO 0.0 0.0 0.0 0.0 0.0 0.0 35.2 0.0 412.4 CO₂ 20352034 2033 2032 2031 2030 2029 2028 2027 Stream # 16.2 143.2 266.0 409.233.6 0.5 0.4 408.8 23.5 Total (1000 lb/hr) 0.0 0.0 0.0 0.0 26.1 0.0 0.00.0 0.0 Methane 0.0 2.7 265.9 268.6 0.0 0.0 0.0 266.6 0.0 Ethylene 0.2140.5 0.0 140.6 0.0 0.0 0.0 138.5 0.2 Ethane 0.0 0.0 0.1 0.0 0.0 0.0 0.03.7 0.0 Acetylene 10.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 10.4 Propene 5.5 0.00.0 0.0 0.0 0.0 0.0 0.0 5.5 Propane 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 7.3C₄₊ Compounds 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 H₂O 0.0 0.0 0.0 0.00.0 0.5 0.4 0.0 0.0 Hydrogen 0.0 0.0 0.0 0.0 0.8 0.0 0.0 0.0 0.0 Argon0.0 0.0 0.0 0.0 4.9 0.0 0.0 0.0 0.0 Nitrogen 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 Oxygen 0.0 0.0 0.0 0.0 1.8 0.0 0.0 0.0 0.0 CO 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 CO₂ 2044 2043 2042 2041 2040 2039 2038 2037 2036Stream # 851.7 524.8 326.9 2066.0 130.1 1935.9 427.3 1508.6 7.2 Total(1000 lb/hr) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Methane 851.7 524.8326.9 0.0 0.0 0.0 0.0 0.0 0.0 Ethylene 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 Ethane 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Acetylene 0.0 0.0 0.02066.0 130.1 1935.9 427.3 1508.6 0.0 Propene 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 Propane 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 7.2 C₄₊ Compounds 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 H₂O 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Hydrogen 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Argon 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 Nitrogen 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Oxygen 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 CO 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0CO₂ 2046 2045 Stream # 1152.1 300.4 Total (1000 lb/hr) 0.0 0.0 Methane1152.1 300.4 Ethylene 0.0 0.0 Ethane 0.0 0.0 Acetylene 0.0 0.0 Propene0.0 0.0 Propane 0.0 0.0 C₄₊ Compounds 0.0 0.0 H₂O 0.0 0.0 Hydrogen 0.00.0 Argon 0.0 0.0 Nitrogen 0.0 0.0 Oxygen 0.0 0.0 CO 0.0 0.0 CO₂

Table 2 shows the temperatures for select streams of the exampleprocess. Stream numbers correspond to those of Examples 4-7 and FIGS.26-31.

TABLE 2 Stream temperatures Stream # Temperature (° F.) 2001 100 2002100 2003 1000 2004 1528 2005 95 2006 1022 2007 100 2008 100 2009 1002010 100 2011 100 2012 100 2013 100 2014 500 2015 501 2016 102 2017 1002018 100 2019 55 2020 43 2021 43 2022 40 2023 55 2024 −30 2025 15 2026−33 2027 145 2028 −17 2029 100 2030 100 2031 100 2032 −9 2033 100 2034−33 2035 126 2036 100 2937 −52 2938 −7 2039 139 2040 59 2041 192 2042−154 2043 −120 2044 −22 2045 −94 2046 83

Example 9 Equipment, Materials of Construction and Utilities

The material of construction for the different process units shown inFIGS. 26-31 is tabulated in the major equipment list (Tables 3-8).Carbon steel material can be used for construction of at least some ormost of the process equipment as the reaction medium is not corrosive.The distillation column shell and, heat exchanger shells can beconstructed out of carbon steel (C.S.) or stainless steel (SS).Distillation column internals are made of stainless steel whereas thereactor shells are constructed of carbon steel. The Transfer LineExchangers used for high pressure steam are made of Mo-Alloy steel.

The process gas compression and treatment section has two pumps and twospares operating at 516 BHP, the product separation and recovery sectionhas four pumps and four spares operating at 1714 BHP, the refrigerationsection has one pump and one spare operating at 128 BHP.

TABLE 3 Reactors and materials of construction Material of Name NumberSize Construction Remarks OCM reactor 111- 19 ft. shell: C.S. 2 sievetrays, 24 inch spacing Stage-I R101 dia 15 ft. trays: 304 SS ReactorBed: H = 8.3 ft., D = 17 ft.; 12″ T-T refractory lining OCM reactor 111-19 ft. shell: C.S. 4 sieve trays, 24 inch spacing Stage-II R102 dia 22ft. trays: 304 SS Reactor Bed: H = 8.3 ft., D = 17 ft.; 12″ T-Trefractory lining, Post Bed Cracking bed height = 7 ft Methanation 111-18 ft. shell: C.S. 2 sieve trays, 24 inch spacing Stage-I R103 dia 20ft. trays: 304 SS Reactor bed: H = 15 ft. T-T Methanation 111- 18 ft.shell: C.S. 2 sieve trays, 24 inch spacing Stage-II R104 dia 20 ft.trays: 304 SS Reactor bed: H = 15 ft. T-T NG 180- 13 ft. shell: C.S. 4sieve trays, 24 inch spacing desulfurization D802A dia 38 ft. trays: 304SS Top reaction bed: H = 6.4 ft. Bottom zinc T-T oxide filter bed: H =26 ft. Acetylene 171- 12 ft. shell: C.S. 2 sieve trays, 24 inch spacinghydrogenation R711 dia reactor 20 ft. trays: 304 SS Reactor bed: H = 15ft. T-T

TABLE 4 Columns and materials of construction Material of Name NumberSize Construction Remarks Process Gas 111- 32 ft. shell: C.S. 10 sievetrays, 12 inch spacing Quench tower-I D109 dia 40 ft. trays: 304 SSProcess Gas 120- 25 ft. shell: C.S. 10 sieve trays, 12 inch spacingQuench tower-II D202 dia 35 ft. trays: 304 SS Process Gas 120- 20 ft.shell: C.S. 10 sieve trays, 12 inch spacing Quench tower-III D203 dia 30ft. trays: 304 SS Demethanizer 150- 18 ft. shell: S.S. 60 valve trays,24 inch spacing T501 dia 155 ft.  trays: 304 SS Top section: D = 18 ft.,H = 35 ft., 15 trays; Bottom section: D = 12 ft., H = 120 ft., 45 traysDeethanizer 170- 11 ft. shell: S.S. 40 sieve trays, 12 inch spacing T701dia 60 ft. trays: 304 SS C₂ splitter 160- 20 ft. shell: C.S. 110 sievetrays, 12 inch spacing T601 dia 140 ft.  trays: 304 SS Depropanizer 190-3.5 ft. shell: C.S. 20 valve trays, 24 inch spacing T801 dia 50 ft.trays: 304 SS

TABLE 5 Compressors and materials of construction Name Number SizeRemarks Process Gas compressor 120-C202/C203 63,500 bhp STEAM turbineStage-I (EACH) Process Gas compressor 120-C204 68,930 bhp STEAM turbineStage-II PSA feed compressor 172-C721  4,700 bhp electric motor EthyleneProduct 160-C601 29,390 bhp 3-stage compressor; steam turbine CompressorPropylene Compressor 175-C751 58,500 bhp 3 stage compressor; steamturbine Ethylene Compressor 176-C761 30,360 bhp Includes 3-stagecompressor with intercoolers; steam turbine

All of the compressors in Table 5 are constructed from carbon steel.

TABLE 6 Heat exchangers and materials of construction Material of NameNumber Size Construction Comments Methane recycle 111-E101 47,300 sq.ft. shell: C.S. heater-I 252.3 tubes: C.S. MMBtu/hr Methanation product111-E102 109,720 sq. ft. shell: C.S. heater (EACH) 1,083 tubes: C.S.MMBtu/hr OCM-I product 111-E103A/B 16,200 sq. ft. shell: Mo alloyTransfer Line Exchanger; cooler-I (EACH) steel generates 1500 psia steam1,330 tubes: Mo alloy MMBtu/hr steel OCM-I product 111-E103C 24,500 sq.ft. shell: C.S. Superheats 1500 psia cooler-II steam to 890° F. 443.5tubes: C.S. MMBtu/hr OCM-II product 111-E104A/B 21,900 sq. ft. shell: Moalloy Transfer Line Exchanger; cooler-I (EACH) steel generates 1500 psiasteam 995 tubes: Mo alloy MMBtu/hr steel OCM-II product 111-E104C 15,990sq. ft. shell: C.S. Superheats 1500 psia cooler-II steam to 890° F.324.4 tubes: C.S. MMBtu/hr Ethane recycle heater 111-E105 20,700 sq. ft.shell: C.S. 163.6 tubes: C.S. MMBtu/hr OCM-II product 111-E106 37,325sq. ft. shell: C.S. cooler-III (EACH) 531.8 tubes: C.S. MMBtu/hr OCM-IIproduct 111-E107 42,450 sq. ft. shell: C.S. cooler-IV 271 tubes: C.S.MMBtu/hr Methane recycle 111-E108 42,480 sq. ft. shell: C.S. heater-II(EACH) 297.9 tubes: C.S. MMBtu/hr Quench tower-I 111-E109 40,700 sq. ft.shell: C.S. Plate and frame cooler (EACH) exchanger 609.9 tubes: 304 SSMMBtu/hr NG feed heater-I HRSG 35,100 sq. ft. shell: C.S. Coil 132.4tubes: C.S. MMBtu/hr Quench tower-II 120-D202 52,750 sq. ft. shell: C.S.Plate and frame cooler exchanger 292.3 tubes: 304 SS MMBtu/hr Quenchtower-III 120-D203 57,530 sq. ft. shell: C.S. Plate and frame coolerexchanger 267.7 tubes: 304 SS MMBtu/hr CO₂ lean gas cooler-I 145-E30118,250 sq. ft. shell: C.S. 81.67 tubes: C.S. MMBtu/hr CO₂ lean gascooler-II 145-E302 8,500 sq. ft. shell: C.S. 9.27 tubes: C.S. MMBtu/hrDemethanizer feed 150-E501 shell: Low temp Custom cold box, cooler C.S.Weight: 44,300 lbs; W: 4.5 ft., H: 5.8 ft. and L: 22 ft. tubes: low tempC.S. Acetylene reactor feed 171-E711 30,970 sq. ft. shell: C.S. heater21.44 tubes: C.S. MMBtu/hr Acetylene reactor 171-E712 4,230 sq. ft.shell: C.S. prod cooler 9.29 tubes: 304 SS MMBtu/hr Deetha OVHD 170-E70122,820 sq. ft. shell: C.S. condenser 30.7 tubes: 304 SS MMBtu/hrDeethanizer reboiler 170-E702 7,900 sq. ft. shell: C.S. 73.6 tubes: C.S.MMBtu/hr C₂ splitter cold box 160-E601/603 shell: C.S. Includes C2splitter tubes: C.S. condenser and reboiler; Weight: 57,465 lbs; W: 4.5ft., H: 6 ft. and l: 27.6 ft. Depropanizer OVHD 190-E801 3,350 sq. ft.shell: C.S. condenser 3.85 tubes: 304 SS MMBtu/hr Depropanizer reboiler190-E802 2,280 sq. ft. shell: C.S. 5.97 tubes: C.S. MMBtu/hr C₄₊ productcooler 190-E803 350 sq. ft. shell: C.S. 0.7 tubes: C.S. MMBtu/hrPropylene cooler 175-E751 48,275 sq. ft. shell: C.S. (EACH) 363.6 tubes:304 SS MMBtu/hr Ethylene cooler 178-E781 49,030 sq. ft. shell: C.S.240.9 tubes: 304 SS MMBtu/hr

TABLE 7 Tanks and materials of construction (stainless steel shell fordemethanizer and deethanizer Name Number Size 50% Caustic Storage900-T901 95,000 gal Spent Caustic Holdup 900-T902 115,000 gal Amine DumpTank 900-T903 150,000 gal Amine Make-up storage 900-T904 4,000 gal C₄₊product storage 900-T905 35,000 gal

TABLE 8 Pressure vessels and materials of construction (stainless steelshell for demethanizer and deethanizer Name Number Size NG feed KO drum180-D801 4,030 gal Process Gas KO drum 145-D301 33,089 gal Deethanizerreflux drum 170-D701 11,037 gal Depropanizer reflux drum 190-D801 476gal Propylene collection drum 175-D754 39,657 gal Propylene Flash Drum-I175-D751 47,000 gal Propylene Flash Drum-II 175-D752 19,829 galPropylene Flash drum-III 175-D753 91,800 gal Ethylene collection drum176-D764 23,460 gal Ethylene Flash drum-I 176-D761 20,305 gal EthyleneFlash drum-II 176-D762 15,640 gal Ethylene Flash drum-III 176-D76328,865 gal

In addition, the process has: a natural gas heater (F-201) 2673 sized 35MMBTU/HR made of carbon steel; three process gas driers (M-201 A-C) 2669each having a capacity of 34,300 gallons made of carbon steel and havingmolecular sieve beds including all peripheral equipment and one sparecolumn; a treated natural gas expander (S-201) 2674 of 4200 HP and madeof carbon steel; a CO2 removal unit (G-201) 2668 made of carbon steeland sized to 11.5 MMSCFD CO2 including an amine scrubber, regeneration,caustic scrubber and peripheral units; a recycle split vapor (RSV) unit(G-301) 2680 made of carbon steel and including a cold box (Width: 4ft., Height: 5.8 ft. and Length: 14.2 ft.), a compressor, twoturboexpanders, and two knockout drums; and a H2 pressure swingadsorption unit (G-302) 2686 made of carbon steel and having a size of4.36 MMSCFD.

The utilities consumed by the process shown in FIGS. 26-31 are tabulatedin Tables 9-10). Table 9 shows the average consumption of the utilitiesand Table 10 shows peak demands imposed upon the utilities. Theutilities are scaled to be able to satisfy both average demands and peakdemands.

TABLE 9 Average utility consumption Battery OCM Compression SeparationLimits Reaction & Treatment and Recovery Refrigeration Units TotalSystem System System Section Cooling Water gpm 244,172 61,088 145,3461,317 36,421 Natural Gas MM Btu/hr 47 N/A 47 N/A N/A Steam, 150 psig Mlb/hr 1,030 N/A 1,030 N/A N/A Steam, 860 psig M lb/hr 1,726 N/A N/A 6251,101 Steam, 1500 psig M lb/hr 2,963 N/A 2,920 43 — Steam, 150 psig Mlb/hr −1,225 N/A N/A −625 −600 Steam, 860 psig M lb/hr −1,977 N/A −1,977N/A N/A Steam, 1500 psig M lb/hr −2,963 −2,963 N/A N/A N/A

TABLE 10 Peak utility consumption Battery OCM Compression SeparationLimits Reaction & Treatment and Recovery Refrigeration Units TotalSystem System System Section Cooling Water gpm 293,007 73,306 174,4161,580 43,705 Electricity kW −6,668 N/A 4,428 −11,202 106 Steam, 150 psigM lb/hr 1,236 — 1,236 N/A N/A Steam, 860 psig M lb/hr 2,071 — N/A 7501,321 Steam, 1500 psig M lb/hr 3,556 — 3,504 52 N/A

It should be understood from the foregoing that, while particularimplementations have been illustrated and described, variousmodifications can be made thereto and are contemplated herein. It isalso not intended that the invention be limited by the specific examplesprovided within the specification. While the invention has beendescribed with reference to the aforementioned specification, thedescriptions and illustrations of the preferable embodiments herein arenot meant to be construed in a limiting sense. Furthermore, it shall beunderstood that all aspects of the invention are not limited to thespecific depictions, configurations or relative proportions set forthherein which depend upon a variety of conditions and variables. Variousmodifications in form and detail of the embodiments of the inventionwill be apparent to a person skilled in the art. It is thereforecontemplated that the invention shall also cover any such modifications,variations and equivalents. It is intended that the following claimsdefine the scope of the invention and that methods and structures withinthe scope of these claims and their equivalents be covered thereby.

What is claimed is:
 1. A method for performing oxidative coupling ofmethane (OCM), comprising: (a) in a substantially adiabatic OCM reactorcomprising a fixed catalyst bed, reacting oxygen (O₂) with methane (CH₄)in an OCM process to yield a product stream comprising (i) compoundswith two or more carbon atoms (C₂₊compounds), including ethylene (C₂H₄),ethane (C₂H₆), and propylene (C₃H₆), (ii) hydrogen (H₂), and (iii)carbon monoxide (CO) or carbon dioxide (CO₂), wherein said OCM processliberates heat, and wherein an inlet temperature of said OCM reactor isat most about 600° C.; (b) directing said product stream from said OCMreactor and C₂H₆ from an ethane stream external to said OCM reactor intoa cracking unit that cracks C₂H₆ using energy derived from said heatliberated in said OCM process, thereby increasing a concentration ofC₂H₄ and H₂ in said product stream; (c) directing said product streamfrom said cracking unit into a compressor that increases a pressure ofsaid product stream using energy derived from said heat liberated insaid OCM process; (d) directing said product stream from said compressorinto a separations unit that enriches said C₂H₄ from said product streamusing energy derived from said heat liberated in said OCM process; and(e) directing H₂ and CO or CO₂ from said product stream from saidseparations unit into a methanation reactor that reacts said H₂ withsaid CO or CO₂ from said product stream to form CH₄.
 2. The method ofclaim 1, wherein at least a portion of said C₂H₆ that is cracked in (b)is produced in said OCM reactor.
 3. The method of claim 1, wherein atleast portion of said ethane stream is from said separations unit. 4.The method of claim 1, wherein said product stream comprises CO and CO₂,and wherein at least a portion of said CO and CO₂ from said productstream is methanated in (e).
 5. The method of claim 1, wherein saidseparations unit enriches said C₂H₄ or C₂₊compounds by removing CH₄, H₂,CO or CO₂.
 6. The method of claim 1, wherein said cracking unit isintegrated with said OCM reactor.
 7. The method of claim 1, wherein atleast a portion of said CH₄ formed in (e) is returned to said OCMreactor.
 8. The method of claim 1, further comprising using a powergeneration unit in thermal communication with said OCM reactor toconvert at least a portion of said heat liberated in said OCM process topower.
 9. The method of claim 1, wherein said product stream comprisesC₂H₆ and H₂.
 10. The method of claim 1, wherein said methane in (a) andsaid C₂H₆ from said ethane stream in (b) are derived from natural gasthat is initially directed into said compressor in (c) or saidseparations unit in (d).
 11. The method of claim 1, wherein saidmethanation reactor has a methanation catalyst that converts CO and/orCO₂ into CH₄ at a selectivity for formation of CH₄ that is at leastabout 10-fold greater than a selectivity of said catalyst for formationof coke from said CO and/or CO₂.
 12. The method of claim 1, wherein saidinlet temperature is from about 460 ° C. to 600 ° C.
 13. The method ofclaim 1, wherein at least a portion of said CH₄ formed in (e) isreturned to said OCM reactor through a heat exchanger.